UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Year Ended December 31, 2005

Commission File Number 1-8796

QUESTAR CORPORATION

STATE OF UTAH                                        1-8796                                87-0407509

(State of other jurisdiction of            (Commission File No.)             (I.R.S. Employer

incorporation or organization)                                                          Identification No.)

Phone:  (801) 324-5000

Securities registered pursuant to Section 12(b) of the Act:

Common stock, without par value,

with attached common stock purchase rights

The above Securities are listed on the New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:  None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  [X]      No  [  ]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  [  ]      No  [X]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  

Yes  [X]      No  [  ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.  (Check one):

Large accelerated filer [X]                               Accelerated filer [  ]                                  Non-accelerated filer [  ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  

Yes [ ]       No [X]

Aggregate market value of the voting common equity held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second quarter (June 30, 2005):  $5,572,015,000 *

On February 28, 2006, 85,488,814 shares of the registrant’s common stock, without par value, were outstanding.

Documents Incorporated by Reference. Portions of the registrant’s definitive Proxy Statement for the 2006 Annual Meeting of Stockholders to be held on May 16, 2006, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2005, are incorporated by reference into Part III. The sections of the Proxy Statement labeled “Committee Report on Executive Compensation” and “Cumulative Total Shareholder Returns” are expressly not incorporated into this document.  

*Calculated by excluding all shares held by directors and executive officers of registrant and three nonprofit foundations established by registrant without conceding that all such persons are affiliates for purposes of federal securities laws.

TABLE OF CONTENTS

Where You Can Find More Information

Forward-Looking Statements

Glossary of Commonly Used Terms

PART I

Item 1.

BUSINESS

Nature of Business

Market Resources

Questar E&P

Wexpro

Gas Management

Energy Trading

Questar Pipeline

Questar Gas

Corporate and Other Operations

Environmental Matters

Employees

Executive Officers

Item 1A.

RISK FACTORS

Item 1B.

UNRESOLVED STAFF COMMENTS

Item 2.

PROPERTIES

Questar E&P

Wexpro

Gas Management

Energy Trading

Questar Pipeline

Questar Gas

Corporate and Other Operations

Item 3.

LEGAL PROCEEDINGS

Item 4.

SUBMISSION OF MATTERS TO A VOTE OF

SECURITY HOLDERS

PART II

Item 5.

MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED

STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY

SECURITIES

Item 6.

SELECTED FINANCIAL DATA

Item 7.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATION

Item 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT

MARKET RISK

Item 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Item 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

ON ACCOUNTING AND FINANCIAL DISCLOSURE

Item 9A.

CONTROLS AND PROCEDURES

Item 9B.

OTHER INFORMATION

PART III

Item 10.

DIRECTORS AND EXECUTIVE OFFICERS OF THE

REGISTRANT

Item 11.

EXECUTIVE COMPENSATION

Item 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Item 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Item 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

PART IV

Item 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

SIGNATURES

Where You Can Find More Information

Questar Corporation (Questar) and its principal subsidiaries, Questar Market Resources, Inc., Questar Pipeline Company and Questar Gas Company, each file annual, quarterly, and current reports with the Securities and Exchange Commission (SEC). Questar also regularly files proxy statements and other documents with the SEC. The public may read and copy these reports and any other materials filed with the SEC at its Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549-0213. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC also maintains a website that contains information filed electronically that can be accessed over the Internet at www.sec.gov.

Investors can also access financial and other information via Questar’s website at www.questar.com. Questar and each of its reporting subsidiaries make available, free of charge, through the website copies of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to such reports and all reports filed by executive officers and directors under Section 16 of the Exchange Act reporting transactions in Questar securities. Access to these reports is provided as soon as reasonably practical after such reports are electronically filed with the SEC. Questar’s website also contains Statements of Responsibility for Board Committees, Corporate Governance Guidelines and its Business Ethics and Compliance Policy.

Finally, you may request a copy of filings, other than an exhibit to a filing unless that exhibit is specifically incorporated by reference into that filing, at no cost by writing or calling Questar, 180 East 100 South Street, P.O. Box 45433, Salt Lake City, Utah 84145-0433 (telephone number (801) 324-5000).

Forward-Looking Statements

This Annual Report may contain or incorporate by reference information that includes or is based upon “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements give expectations or forecasts of future events. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,“ “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” and other words and terms of similar meaning in connection with a discussion of future operating or financial performance. In particular, these include statements relating to future actions, prospective services or products, future performance or results of current and anticipated services or products, exploration efforts, expenses, the outcome of contingencies such as legal proceedings, trends in operations and financial results.

Any or all forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. These statements are based on current expectations and the current economic environment. They involve a number of risks and uncertainties that are difficult to predict. These statements are not guarantees of future performance. Actual results could differ materially from those expressed or implied in the forward-looking statements. Among factors that could cause actual results to differ materially are:

•

the risk factors discussed in Part I, Item 1A. of this Annual Report;

•

general economic conditions, including the performance of financial markets and interest rates;

•

changes in industry trends;

•

changes in laws or regulations; and

•

other factors, most of which are beyond control.

Questar undertakes no obligation to publicly correct or update the forward-looking statements in this Annual Report, in other documents, or on the website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.

Glossary of Commonly Used Terms

B

Billion

bbl

Barrel, which is equal to 42 U.S. gallons and is a common measure of volume of crude oil and other liquid hydrocarbons.

basis

The difference between a reference or benchmark commodity price and the corresponding sales price at various regional sales points.

Btu

One British thermal unit – a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.

cash-flow hedge

A derivative instrument that complies with Statement of Financial Accounting Standards (SFAS) 133, as amended, and is used to reduce the exposure to variability in cash flows from the forecasted physical sale of gas and oil production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted physical sale.

cf

Cubic foot is a common unit of gas measurement. One standard cubic foot equals the volume of gas in one cubic foot measured at standard conditions – a temperature of 60 degrees Fahrenheit and a pressure of 30 inches of mercury (approximately 14.7 pounds per square inch).

cfe

Cubic feet of natural gas equivalents

development well

A well drilled into a known producing formation in a previously discovered field.

dewpoint

A specific temperature and pressure at which hydrocarbons condense to form a liquid.

dry hole

A well drilled and found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of production exceed expenses and taxes.

dth

Decatherms or ten therms. One dth equals one million Btu or approximately one Mcf.

dthe

Decatherms of natural gas equivalents

equity production

Production at the wellhead attributed to Questar ownership.

exploratory well

A well drilled into a previously untested geologic prospect to determine the presence of gas or oil.

finding costs

Finding costs are the sum of costs incurred for gas and oil exploration and development activities; including purchases of reserves in place, leasehold acquisitions, seismic, geological and geophysical, development and exploration drilling and asset retirement obligations for a given period, divided by the total amount of estimated net proved reserves added through discoveries, positive and negative revisions and purchases in place for the same period. The Company expresses finding costs in dollars per Mcfe averaged over a five-year period.

frac spread

The difference between the market price for NGLs extracted from the gas stream and the market value of the Btu-equivalent volume of natural gas required to replace the extracted liquids.

futures contract

An exchange-traded contract to buy or sell a standard quantity and quality of a commodity at a specified future date and price.

gal

U.S. gallon.

gas

All references to “gas” in this report refer to natural gas.

gross

“Gross” natural gas and oil wells or “gross” acres equal the total number of wells or acres in which the Company has a working interest.

heating degree days

A measure of the number of degrees the average daily outside temperature is below 65 degrees Fahrenheit.

hedging

The use of derivative-commodity and interest-rate instruments to reduce financial exposure to commodity price and interest-rate volatility.

infill development drilling

Drilling wells between established producing wells; a drilling program to reduce the spacing between wells in order to increase production and/or recovery of in-place hydrocarbons.

lease operating expenses

The expenses, usually recurring, which are incurred to operate the wells and equipment on a producing lease.

M

Thousand.

MM

Million.

natural gas equivalents

Oil and NGL volumes are converted to natural gas equivalents using the ratio of one barrel of crude oil, condensate or NGL to 6,000 cubic feet of natural gas.

natural gas liquids (NGL)

Liquid hydrocarbons that are extracted and separated from the natural gas stream. NGL products include ethane, propane, butane, natural gasoline and heavier hydrocarbons.

net

“Net” gas and oil wells or “net” acres are determined by the sum of the fractional ownership working interest the Company has in those gross wells or acres.

net revenue interest

A share of production after all burdens, such as royalties and overriding royalties, have been deducted from the working interest. It is the percentage of production that each owner actually receives.

production replacement ratio

The production replacement ratio is calculated by dividing the net proved reserves added through discoveries, positive and negative revisions and purchases and sales in-place for a given period by the production for the same period, expressed as a percentage. The production replacement ratio is typically reported on an annual basis.

proved reserves

Those quantities of natural gas, crude oil, condensate and NGL on a net revenue interest basis, which geological and engineering data demonstrate with reasonable certainty to be recoverable under existing economic and operating conditions. See 17 C.F.R. Section 4-10(a)(2) for a complete definition.

proved developed reserves

Reserves that include proved developed producing reserves and proved developed nonproducing reserves. See 17 C.F.R. Section 4-10(a)(3).

proved developed producing reserves

Reserves expected to be recovered from existing completion intervals in existing wells.

proved undeveloped reserves

Reserves expected to be recovered from new wells on proved undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. See 17 C.F.R. Section 4-10(a)(4).

reservoir

A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

royalty

An interest in an oil and gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

seismic

An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of a subsurface rock formation. (2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional views.)

wet gas

Unprocessed natural gas that contains a mixture of heavier hydrocarbons including ethane, propane, butane and natural gasoline.

working interest

An interest in an oil and gas lease that gives the owner the right to drill, produce and conduct operating activities on the leased acreage and receive a share of any production.

workover

Operations on a producing well to restore or increase production.

FORM 10-K

ANNUAL REPORT, 2005

PART I

ITEM 1.  BUSINESS.

Nature of Business

Questar Corporation (Questar or the Company) is a natural gas-focused energy company with four major lines of business – gas and oil exploration and production, midstream field services, interstate gas transportation, and retail gas distribution – which are conducted through its three principal subsidiaries. Questar Market Resources, Inc. (Market Resources) engages in gas and oil exploration, development and production and midstream field services-gas gathering and processing, as well as wholesale gas and oil marketing and gas storage. Questar Pipeline Company (Questar Pipeline) provides interstate natural gas transportation and storage services. Questar Gas Company (Questar Gas) provides retail natural gas distribution. See Note 15 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for financial information concerning Questar's lines of business that contribute 10% or more of consolidated revenues.

Questar is a holding company, as that term is defined in the Public Utility Holding Company Act of 2005 (PUHCA 2005), because its subsidiary Questar Gas is a gas utility company. Questar, however, qualifies for and will file for an exemption and waiver from provisions of the Act applicable to holding companies. PUHCA 2005 supersedes the Public Utility Holding Company Act of 1935 under which Questar qualified for an exemption. Questar conducts most of its operations through subsidiaries. The parent-holding company performs certain management, legal, tax, administrative and other services for its subsidiaries

Questar operates in the Rocky Mountain and Midcontinent regions of the United States of America and is headquartered in Salt Lake City, Utah. Shares of Questar common stock trade on the New York Stock Exchange under the symbol STR.

The corporate-organization structure and major subsidiaries are summarized below:

Market Resources

Market Resources is a natural gas-focused energy company, a wholly owned subsidiary of Questar and Questar’s primary growth driver. Market Resources is a sub-holding company with four principal subsidiaries: Questar Exploration and Production Company (Questar E&P) acquires, explores for, develops and produces natural gas, oil, and NGL; Wexpro Company (Wexpro) manages, develops and produces cost-of-service reserves for affiliated company, Questar Gas; Questar Gas Management Company (Gas Management) provides midstream field services including natural gas-gathering and processing services for affiliates and third parties; and Questar Energy Trading Company (Energy Trading) markets equity and third-party gas and oil, provides risk-management services, and through its wholly owned limited liability company, Clear Creek Storage Company, LLC, owns and operates an underground natural gas-storage reservoir.

Questar E&P

Questar E&P operates in two core areas – the Rocky Mountain region of Wyoming, Utah and Colorado and the Midcontinent region of Oklahoma, Texas and Louisiana. Questar E&P has a large inventory of identified development drilling locations, primarily on the Pinedale Anticline in western Wyoming and in the Uinta Basin of Utah. Questar E&P continues to conduct exploratory drilling to determine commerciality of its inventory of undeveloped leaseholds located primarily in the Rocky Mountain region, including the assessment of deeper reservoirs under approximately 143,000 net leasehold acres in the Vermillion Basin of southwest Wyoming and northwestern Colorado. In the Midcontinent, Questar E&P has several active development projects, including an ongoing coalbed methane project in the Arkoma Basin of eastern Oklahoma and an infill development drilling project in the Elm Grove area in northwestern Louisiana. Questar E&P seeks to maintain geographical and geological diversity with its two core areas. Questar E&P has in the past and may in the future pursue acquisition of producing properties through the purchase of assets or corporate entities to expand its presence in its core areas or create a new core area.

Questar E&P reported 1,480 Bcfe of estimated proved reserves as of December 31, 2005. Approximately 80% of Questar E&P’s proved reserves, or 1,179 Bcfe, were located in the Rocky Mountain region of the United States, while the remaining 20%, or 301 Bcfe, were located in the Midcontinent region. Approximately 920 Bcfe of the proved reserves reported by Questar E&P at year-end 2005 were developed, while 560 Bcfe were proved undeveloped. The majority of the proved undeveloped reserves were associated with the Company’s Pinedale Anticline leasehold. Questar E&P’s primary focus is natural gas. Natural gas comprised about 90% of Questar E&P’s total proved reserves at year-end 2005. See Item 2 in Part I and Note 17 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on Questar E&P’s proved reserves.

Questar E&P – Competition and Customers

Questar E&P faces competition in every part of its business, including the acquisition of reserves and leases. Its longer-term growth strategy depends, in part, on its ability to purchase reasonably priced reserves and develop them in a low-cost and efficient manner. Competition is particularly intense when prices are high, as has been the case in recent years.

Questar E&P, through Energy Trading, sells natural gas production to a variety of customers, including pipelines, gas-marketing firms, industrial users and local-distribution companies. It regularly evaluates counterparty credit and may require financial guarantees from parties that fail to meet its credit criteria. Energy Trading sells equity crude-oil production to refiners, remarketers and other companies, including some with pipeline facilities near company producing properties. In the event pipeline facilities are not available, Energy Trading transports crude oil by truck to storage, refining or pipeline facilities.

Questar E&P – Regulation

Questar E&P's operations are subject to various government controls and regulation at the federal, state and local levels. Questar E&P must obtain permits to drill and produce; maintain bonding requirements to drill and operate wells; submit and implement spill-prevention plans; and file notices relating to the presence, use, and release of specified contaminants incidental to gas and oil production. Questar E&P is also subject to various conservation matters, including the regulation of the size of drilling and spacing units, the number of wells that may be drilled in a unit and the unitization or pooling of gas and oil properties.

Most Questar E&P leases in the Rocky Mountain area are granted by the federal government and administered by federal agencies. Development of Pinedale leasehold acreage is subject to the terms of certain winter-drilling restrictions. During the last two years, Market Resources has been working with federal and state officials in Wyoming to obtain authorization for limited winter-drilling activities and has developed innovative measures, such as drilling multiple wells from a single location, to minimize the impact of its activities on wildlife and wildlife habitat. The presence of wildlife and potential endangered species could limit access to public lands. Various wildlife species inhabit Market Resources leaseholds at Pinedale and in other areas. Current federal regulations restrict activities during certain times of the year on portions of Market Resources leaseholds due to wildlife activity and/or habitat. Some species that are known to be present may be listed under federal law as endangered or threatened. Such listing could have a material impact on access to Market Resources leaseholds in certain areas or during periods when the particular species is present.

Wexpro

Wexpro develops and produces gas and oil on certain properties owned by affiliate Questar Gas under the terms of a comprehensive agreement, the Wexpro Agreement. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19% on its investment in commercial wells and related facilities – adjusted for working capital and reduced for deferred income taxes and depreciation – its investment base. The term of the Wexpro Agreement coincides with the productive life of the gas and oil properties covered therein. Wexpro’s investment base totaled $206.3 million at December 31, 2005.

Wexpro delivers natural gas production to Questar Gas at a price equal to Wexpro’s cost-of-service. Wexpro cost-of-service gas satisfied 41% of Questar Gas system requirements during 2005 at cost of service pricing that is significantly lower than Questar Gas cost for purchased gas.

Wexpro gas and oil-development and production activities are subject to the same type of regulation as Questar E&P. In addition, the Utah Division of Public Utilities has oversight responsibility and retains an outside reservoir-engineering consultant and a financial auditor to assess the prudence of Wexpro’s activities.

Wexpro owns oil-producing properties. Under terms of the Wexpro Agreement, revenues from crude-oil sales offset operating expenses and provide Wexpro with a return on its investment. Any remaining revenues, after recovery of expenses and Wexpro's return on investment, are divided between Wexpro (46%) and Questar Gas (54%).

Wexpro operations are contractually limited to a finite set of properties set forth in the Wexpro Agreement. Advances in technology (pad drilling and multi-stage hydraulic fracture stimulation) have unlocked significant unexploited potential on many of the subject properties. Wexpro has identified $600 to $750 million of additional drilling opportunities that could support high single-digit to low double-digit growth in revenues and net income over the next five to ten years while delivering cost-of-service natural gas supplies to Questar Gas at prices competitive with alternative sources.

See Note 14 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Wexpro Agreement.

Gas Management

Gas Management provides natural gas-gathering and processing services to affiliates and third-party producers in the Rocky Mountain region. Gas Management also owns 50% of Rendezvous Gas Services, LLC, (Rendezvous), a joint venture that operates gas-gathering facilities in western Wyoming. Rendezvous gathers natural gas for Pinedale Anticline and Jonah field producers for delivery to various interstate pipelines. Under a contract with Questar Gas, Gas Management also gathers cost-of-service volumes produced from properties operated by Wexpro.

Approximately 56% of Gas Management's revenues are derived from fee-based gathering and processing agreements. The remaining revenues are derived from natural gas processing margins that are in part exposed to the frac spread. To reduce processing margin risk, Gas Management has restructured many of its processing agreements with producers from “keep-whole” contracts to “fee-based” contracts. A keep-whole contract insulates producers from frac spread risk while a fee-based contract eliminates commodity price risk for the processing plant owner. To further reduce processing margin volatility associated with keep-whole contracts, Gas Management may also attempt to reduce processing margin risk with forward-sales contracts for NGL or hedge NGL prices and equivalent gas volumes with the intent to lock in a processing margin.

Energy Trading

Energy Trading markets natural gas, oil and NGL. It combines gas volumes purchased from third parties and equity production to build a flexible and reliable portfolio. As a wholesale marketing entity, Energy Trading concentrates on markets in the Rocky Mountains, Pacific Northwest and Midcontinent that are close to reserves owned by affiliates or accessible by major pipelines. It contracts for firm-transportation capacity on pipelines and firm-storage capacity at Clay Basin, a large baseload-storage facility owned by affiliate Questar Pipeline. Energy Trading, through its Clear Creek Storage Company, LLC, operates an underground gas-storage reservoir in southwestern Wyoming. It uses owned and leased-storage capacity together with firm-transportation capacity to take advantage of price differentials and arbitrage opportunities.

Energy Trading uses derivatives to manage commodity price risk. Energy Trading primarily uses fixed-price swaps to secure a known price for a specific volume of company production. Energy Trading does not engage in speculative hedging transactions. See Notes 1 and 10 to the consolidated financial statements included in Item 8 and Quantitative and Qualitative Disclosures About Market Risk in Item 7A in Part II of this Annual Report for additional information relating to hedging activities.

Questar Pipeline

Questar Pipeline is an interstate pipeline company that provides natural gas-transportation and underground storage services in Utah, Wyoming and Colorado. As a “natural gas company” under the Natural Gas Act of 1938, Questar Pipeline and certain subsidiary pipeline companies are regulated by the Federal Energy Regulatory Commission (FERC) as to rates and charges for storage and transportation of natural gas in interstate commerce, construction of new facilities, and extensions or abandonments of service and facilities, accounting and other activities.

Questar Pipeline and its subsidiaries own 2,499 miles of interstate pipeline with total daily capacity of 3,399 Mdth. Questar Pipeline's core-transmission system is strategically located in the Rocky Mountain area near large reserves of natural gas in six major Rocky Mountain producing areas. Questar Pipeline transports natural gas from these producing areas to other major pipeline systems and to the Questar Gas distribution system. In addition to this core system, Questar Pipeline, through a subsidiary, owns and operates the Southern Trails Pipeline, a 488-mile line that extends from the Blanco hub in the San Juan Basin to just inside the California state line.

Questar Pipeline owns and operates the Clay Basin storage facility, the largest underground- storage reservoir in the Rocky Mountain region. Through a subsidiary, Questar Pipeline also owns gathering lines and a processing plant near Price, Utah, which provides heat-content-management services for Questar Gas and carbon-dioxide extraction for third parties.

Questar Pipeline – Customers, Growth and Competition

Questar Pipeline faces risk of recontracting firm capacity as contract terms expire. Questar Pipeline’s transportation system is nearly fully subscribed, and firm contracts had a weighted-average remaining life of 10.9 years as of December 31, 2005. All of Questar Pipeline storage capacity is fully contracted with a weighted-average remaining life of 8.0 years as of December 31, 2005.

Questar Gas remains Questar Pipeline's largest transportation customer. During 2005, Questar Pipeline transported 116.3 MMdth for Questar Gas compared to 116.5 MMdth in 2004. Questar Gas has reserved firm-transportation capacity of 951 Mdth per day under long-term contracts, or about 50% of Questar Pipeline's reserved capacity, during the three coldest months of the year. Questar Pipeline's primary transportation agreement with Questar Gas will expire on June 30, 2017.

Questar Pipeline also transported 259.3 MMdth for nonaffiliated customers to pipelines owned by Kern River Pipeline, Northwest Pipeline, Colorado Interstate Gas, TransColorado, Wyoming Interstate Company and other systems. Questar Pipeline may be adversely affected by proposals before the FERC to establish natural gas-quality standards, specifically for hydrocarbon dewpoint. Questar Pipeline's tariff allows a higher hydrocarbon dewpoint specification than most other systems, which requires less processing by producers before natural gas volumes are delivered into Questar Pipeline's system. As a consequence, Questar Pipeline must incur higher costs to blend lower dewpoint-processed gas with wet gas and in some instances isolate processed gas for delivery to other pipelines. In effect, Questar Pipeline currently provides a bundled gas-transportation and dewpoint-management service for shippers at certain delivery points. Questar Pipeline may need to restructure its tariff to unbundle these services.

During 2005, Questar Pipeline expanded its southern system in central Utah. This expansion was completed and placed into service in the fourth quarter of the year and added 102 Mdth of daily capacity under long-term contracts. Questar Pipeline received FERC approval for the expansion in January 2005. Also, Questar Pipeline began service to a new power plant near Mona, Utah in the second quarter of 2005. These projects will contribute about $3 million in net income per year.

Rocky Mountain producers, marketers and end-users seek capacity on interstate pipelines that move gas to California (Kern River), the Pacific Northwest (Northwest Pipeline) or Midwestern markets (Wyoming Interstate Company and Colorado Interstate Gas). Questar Pipeline provides access for many producers to these third-party pipelines. Some parties, including Gas Management, an affiliate of Questar Pipeline, are building gathering lines that allow producers to make direct connections to competing pipeline systems.

Questar Pipeline seeks to extend and expand its core pipeline and storage business. Questar Pipeline has proposed to further expand its southern system in central Utah. In addition, Questar Pipeline and other pipelines have proposed projects to connect northwestern Colorado and southwestern Wyoming gas supplies with pipelines moving gas east out of Wyoming. Following successful open seasons in 2005, Questar Pipeline is finalizing contracts with customers to support these new projects. Questar Pipeline is also assessing the feasibility of a gas-storage project in western Wyoming.

Southern Trails Pipeline.  In mid-2002, Questar Southern Trails Pipeline, a Questar Pipeline subsidiary, placed the eastern segment of the Southern Trails pipeline into service. The eastern segment extends from the San Juan Basin to inside the California border. Capacity on this segment is fully committed under contracts that expire in mid-2008 and mid-2015.

The California segment of the Southern Trails Pipeline, which extends from near the California-Arizona border to Long Beach, California, is currently not in service. Questar Pipeline is pursuing several options to sell or place this line in service.

See Note 4 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for discussion of an impairment of the California segment of Southern Trails.

Questar Pipeline – Regulation

FERC Order No. 2004 requires employees engaged in transportation system operations to function independently from employees of marketing and energy affiliates. In addition a transportation provider must treat all transportation customers on a non-discriminatory basis and must not operate its transportation system to preferentially benefit its marketing or energy affiliates. Questar Pipeline has determined that all Market Resources subsidiaries except Gas Management are marketing or energy affiliates. Questar Gas is not an energy or marketing affiliate.

Questar Pipeline is required to comply with the Pipeline Safety Improvement Act of 2002. This Act and the rules issued by the DOT require interstate pipelines and local distribution companies to implement a 10-year program of risk analysis, pipeline assessment and remedial repair for transportation pipelines located in high-consequence areas such as densely populated locations. Questar Pipeline’s annual cost to comply with the Act is approximately $1 million, not including costs of pipeline replacement, if necessary.

Clay Basin Storage Gas.  See Results of Operation included in Item 7 of Part II of this Annual Report for discussion of Clay Basin storage gas loss.

Questar Gas

Questar Gas distributes natural gas as a public utility in Utah, southwestern Wyoming and a small portion of southeastern Idaho. As of December 31, 2005, Questar Gas was serving 824,447 sales and transportation customers. Questar Gas is the only non-municipal gas-distribution utility in Utah, where over 96% of its customers are located. The Public Service Commission of Utah (PSCU), the Public Service Commission of Wyoming (PSCW) and the Public Utility Commission of Idaho have granted Questar Gas the necessary regulatory approvals to serve these areas. Questar Gas also has long-term franchises granted by communities and counties within its service area.

Questar Gas growth is tied to the economic growth of Utah and southwestern Wyoming. It has over 90% of the load for residential space heating and water heating in its service territory. During 2005, Questar Gas added a record 30,330 customers, a 3.8% increase.

Questar Gas faces the same risks as other local-distribution companies. These risks include revenue variations based on seasonal changes in demand, sufficient gas supplies, declining residential usage per customer, adequate distribution facilities and adverse regulatory decisions. Questar Gas's sales to residential and commercial customers are seasonal, with a substantial portion of such sales made during the heating season. The typical residential customer in Utah (defined as a customer using 115 dth per year) consumes over 77% of total gas requirements in the coldest six months of the year. Questar Gas, however, has a weather-normalization mechanism for its general-service customers. This mechanism adjusts the non-gas portion of a customer's monthly bill as the actual heating-degree days in the billing cycle are warmer or colder than normal. This mechanism reduces dramatic fluctuations in any given customer's monthly bill from year to year and reduces fluctuations in Questar Gas gross margin.

Questar Gas minimizes gas supply risks by owning natural gas reserves. During 2005, Questar Gas satisfied 41% of its system requirements with the cost-of-service gas and associated royalty-interest volumes. Wexpro produces the gas from these properties, which is then gathered by Gas Management and transported by Questar Pipeline. Questar Gas had estimated proved cost-of-service natural gas reserves of 497.3 Bcf as of year-end 2005 compared to 531.1 Bcf a year earlier. Questar Gas also has a balanced and diversified portfolio of gas-supply contracts for volumes produced in Wyoming, Colorado, and Utah. Questar Gas has regulatory approval to include costs associated with hedging activities in its balancing account for pass-through treatment.

Questar Gas has designed its distribution system and annual gas-supply plan to handle design-day demand requirements. It periodically updates its design-day demand, the volume of gas that firm customers could use during extremely cold weather. For the 2005-06 heating season, Questar Gas used a design-day demand of 1,106 Mdth for firm customers.  

Questar Gas has long-term contracts with Questar Pipeline for transportation and storage capacity at Clay Basin and three peak-day storage facilities. Questar Gas also has contracts to take deliveries at several locations on the Kern River Pipeline.

Questar Gas – Regulation

As a public utility, Questar Gas is subject to the jurisdiction of the PSCU and PSCW. Natural gas sales and transportation services are made under rate schedules approved by the two regulatory commissions. Questar Gas is authorized to earn a return on equity of 11.2% in Utah and 11.83% in Wyoming. Both the PSCU and PSCW permit Questar Gas to recover gas costs through a balancing-account procedure and to reflect natural gas-price changes on a periodic, generally semi-annual basis. Questar Gas has also received permission from the PSCU and PCSW to reflect in its gas costs specified costs associated with hedging contracts.

See Note 2 of the consolidated financial statements included in Item 8 of Part II in this Annual Report for a discussion of gas-processing cost coverage.

Questar Gas has significant relationships with affiliates that have allowed it to lower its costs and improve efficiency. These affiliate relationships, however, are subject to oversight by regulatory commissions for evidence of subsidization and above-market payments.

Questar Gas is subject to the requirements of the Pipeline Safety Improvement Act. Questar Gas estimates that it will cost $4.0 to $5.0 million per year to comply with the Act, not including costs of pipeline replacement if necessary. The PSCU has allowed Questar Gas to record a regulatory asset for these incremental operating costs incurred to comply with this Act until the next rate case or 2007, whichever is sooner.

Questar Gas – Competition

Questar Gas is a public utility and currently has no direct competition from other distributors of natural gas for residential and commercial customers. It has historically enjoyed a favorable price comparison with other energy sources used by residential and commercial customers except coal and occasionally fuel oil. It provides transportation service to industrial customers that can buy volumes of gas directly from others. Questar Gas earns lower margins on this transportation service than firm-sales service and could lose customers to Kern River.

Corporate and Other Operations

Historically, Questar's Other Operations included information-technology and communication services; web-hosting and data centers (Consonus); commercial real-estate management; and wellhead gas analysis and automation, field compression and engine maintenance (Energy Services). Questar reorganized these activities in 2004 and 2005 to refocus attention on its primary business activities and reduce costs. Questar has no plans to enlarge the scope of these activities. The majority of information-technology employees and assets were transferred to the separate business segments, and the assets of Consonus were sold. The scope of commercial real estate activities was significantly reduced. Energy Services focuses on wellhead automation and gas analysis.

Environmental Matters

A discussion of Questar’s environmental matters is included in Item 3. Legal Proceedings of Part I in this Annual Report.

Employees

At January 1, 2006, the Company had 2,105 employees, including 601 in Market Resources, 178 in Questar Pipeline, 1,170 in Questar Gas, and 156 in Corporate and Other Operations.

Executive Officers

The following individuals are serving as executive officers of the Company:

Primary Positions Held with the Company

and Affiliates, Other Business Experience

Name

Keith O. Rattie

52

Chairman (2003); President (2001); Chief Executive Officer (2002); Director (2001); Chief Operating Officer (2001 to 2002); Director, Questar affiliates (2001). Prior to coming to Questar, Mr. Rattie served successively as Vice President and Senior Vice President of the Coastal Corporation (1996 to 2001).

Charles B. Stanley

47

Executive Vice President, Director Questar (2002); President, Chief Executive Officer and Director, Market Resources and Market Resources subsidiaries (2002); Senior Vice President, Questar (2002 to 2002); Executive Vice President and Chief Operating Officer, Market Resources and Market Resources subsidiaries (2002 to 2002). Prior to joining Questar, Mr. Stanley was President, Chief Executive Officer and Director, Coastal Gas International Co. (1995 to 2000); President and Chief Executive Officer, El Paso Oil and Gas Canada, Inc. (2000 to January 2002).  

Alan K. Allred

55

Executive Vice President, Questar (2003); President and Chief Executive Officer and Director, Questar Regulated Services and Questar Gas (2003); Chief Executive Officer and Director, Questar Pipeline (2003 to 2006); President, Questar Pipeline (2003 to 2005); Executive Vice President and Chief Operating Officer, Questar Regulated Services, Questar Gas and Questar Pipeline (2002 to 2003); Senior Vice President, Questar Regulated Services, Questar Gas and Questar Pipeline (2002 to 2002); Vice President, Business Development, Questar Regulated Services, Questar Gas and Questar Pipeline (2000 to 2002); Manager, Regulatory Affairs, Questar Gas and Questar Pipeline (1997 to 2000).

R. Allan Bradley

54

Senior Vice President, Questar (2005); Chief Executive Officer, Questar Pipeline (2006); President, Chief Operating Officer and Director, Questar Pipeline (2005); Prior to joining Questar, Mr. Bradley was Managing Director and founding member, Ventura Energy LLC (2002 to 2004) and Senior Vice President, Coastal Corporation and El Paso Corporation affiliates (1990-2002).

Stephen E. Parks

54

Senior Vice President and Chief Financial Officer (2001); Chief Financial Officer (1996); Treasurer (1984 to 2004); Vice President (1990 to 2001); Vice President, Treasurer and Chief Financial Officer of all affiliates (at various dates beginning 1984); and Director Market Resources subsidiaries (at various dates beginning in 1996).

Thomas C. Jepperson

51

Vice President and General Counsel, Questar (2005); Division Counsel (2000 to 2004); Managing Attorney (1990 to 1999) and Senior Attorney (1988 to 1989) for Market Resources; prior to joining Questar, Mr. Jepperson was a partner of the law firm Nielsen and Senior (Salt Lake City).

Brent L. Adamson

54

Vice President Ethics, Compliance and Audit (2002); Director, Audit (1982 to 2002); Compliance Officer (1995 to 2002).

There is no “family relationship” between any of the listed officers or between any of them and the Company's directors. The executive officers serve at the pleasure of the Board of Directors. There is no arrangement or understanding under which the officers were selected.

ITEM 1A. RISK FACTORS.

Investors should read carefully the following factors as well as the cautionary statements referred to in “Forward-Looking Statements” herein. If any of the risks and uncertainties described below or elsewhere in this Annual Report actually occur, the Company’s business, financial condition or results of operations could be materially adversely affected.

The future price of natural gas, oil and NGL is unpredictable.  Historically the price of natural gas, oil and NGL has been volatile and is likely to continue to be volatile in the future. Any significant or extended decline in commodity prices would impact the Company’s future financial condition, revenues, results of operations, cash flows and rate of growth. Because approximately 90% of Questar’s proved reserves at December 31, 2005, was natural gas, the Company is substantially more sensitive to changes in natural gas prices than to changes in oil prices.

Questar cannot predict the future price of natural gas, oil and NGL because of factors beyond its control, including but not limited to:

*

changes in domestic and foreign supply of natural gas, oil and NGL;

*

changes in local, regional, national and global demand for natural gas, oil, and NGL;

*

regional price differences resulting from available pipeline transportation capacity or local demand;

*

the level of imports of, and the price of, foreign natural gas, oil and NGL;

*

domestic and global economic conditions;

*

domestic political developments;

*

weather conditions;

*

domestic and foreign government regulations and taxes;

*

political instability or armed conflict in oil and natural gas producing regions;

*

the price, availability and acceptance of alternative fuels;

*

U.S. storage levels of natural gas, oil, and NGL.

Questar uses derivative instruments to manage exposure to uncertain prices.  Questar uses financial contracts to hedge exposure to volatile natural gas, oil, and NGL prices and to protect cash flow, returns on capital, net income and credit ratings from downward commodity price movements. To the extent the Company hedges commodity price exposure, it forgoes the benefits otherwise experienced if commodity prices increase. Questar believes its regulated businesses – interstate natural gas transportation and retail gas distribution – and its Wexpro subsidiary generate revenues that are not significantly sensitive to short-term fluctuations in commodity prices.

Questar enters into commodity price hedging arrangements with creditworthy counterparties (banks and industry participants) with a variety of credit requirements. Some contracts do not require the Company to post cash collateral, while others allow some amount of credit before requiring deposits of collateral for out-of-the-money hedges. The amount of credit available may vary depending on the credit rating assigned to the Company’s debt securities. A substantial increase in the price of natural gas, oil and/or NGL could result in the requirement to deposit large amounts of collateral with counterparties that could seriously impact the Company’s cash liquidity. Additionally a downgrade in the Company’s credit ratings to sub-investment grade could result in the acceleration of obligations to hedge counterparties.

The Company may not be able to economically find and develop new reserves.  The Company’s profitability depends not only on prevailing prices for natural gas, oil and NGL, but also its ability to find, develop and acquire gas and oil reserves that are economically recoverable. Substantial capital expenditures are required to find, develop and acquire gas and oil reserves to replace those depleted by production.

Gas and oil reserve estimates are imprecise and subject to revision.  Questar E&P’s proved natural gas and oil reserve estimates are prepared annually by independent reservoir-engineering consultants. Gas and oil reserve estimates are subject to numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and timing of development expenditures. The accuracy of these estimates depends on the quality of available data and on engineering and geological interpretation and judgment. Reserve estimates are imprecise and will change as additional information becomes available. Estimates of economically recoverable reserves and future net cash flows prepared by different engineers, or by the same engineers at different times may vary significantly. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. In addition the estimation process also involves economic assumptions relating to commodity prices, production costs, severance and other taxes, capital expenditures and remedial costs. Actual results most likely will vary from the estimates. Any significant variance could reduce the estimated future net revenues from proved reserves and the present value of those reserves.

Investors should not assume that the “standardized measure of discounted future net cash flows” from Questar E&P’s proved reserves referred to in this Annual Report is the current market value of the estimated natural gas and oil reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from Questar E&P’s proved reserves is based on prices and costs in effect on the date of the estimate, holding the prices constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the current estimate, and future determinations of the standardized measure of discounted future net cash flows using then current prices and costs may be significantly less than the current estimate.

Questar faces many operating risks to develop and produce its reserves.  Drilling is a high-risk activity. Operating risks include: fire, explosions and blow-outs; unexpected drilling conditions such as abnormally pressured formations; abandonment costs; pipe, cement or casing failures; environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine or well fluids (including groundwater contamination). The Company could incur substantial losses as a result of injury or loss of life; pollution or other environmental damage; damage to or destruction of property and equipment; regulatory investigation; fines or curtailment of operations; or attorney’s fees and other expenses incurred in the prosecution or defense of litigation.  

As is customary in the oil and gas industry, the Company maintains insurance against some, but not all, of these potential risks and losses. Questar can not assure that insurance will be adequate to cover these losses or liabilities. Losses and liabilities arising from uninsured or underinsured events could have an adverse effect on the Company’s financial condition and operations.

Shortages of oilfield equipment, services and qualified personnel could impact results of operations.  The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. There have also been shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate increased demand and result in increased costs for drilling rigs, crews and associated supplies, equipment and services. These shortages or cost increases could impact profit margin, cash flow and operating results or restrict the ability to drill wells and conduct operations.

A significant portion of Market Resources production, revenue and cash flow are derived from assets that are concentrated in a geographical area. While geographic concentration of assets provides scope and scale that can reduce operating costs and provide other operating synergies, asset concentration does increase exposure to certain risks. Market Resources has extensive operations on the Pinedale Anticline and in the Greater Green River Basin of southwestern Wyoming. Any circumstance or event that negatively impacts the operations of Questar E&P, Wexpro or Gas Management in that area could materially reduce earnings and cash flow.

Questar is subject to complex regulations on many levels.  The Company is subject to federal, state and local environmental, health and safety laws and regulations. Environmental laws and regulations are complex, change frequently and tend to become more onerous over time. In addition to the costs of compliance, substantial costs may be incurred to take corrective actions at both owned and previously owned facilities. Accidental spills and leaks requiring cleanup may occur in the ordinary course of business. As standards change, the Company may incur significant costs in cases where past operations followed practices that were considered acceptable at the time but that now require remedial work to meet current standards. Failure to comply with these laws and regulations may result in fines, significant costs for remedial activities, or injunctions.

Questar must comply with numerous and complex regulations governing activities on federal and state lands in the Rocky Mountain region, notably the National Environmental Policy Act, the Endangered Species Act, and the National Historic Preservation Act. Federal and state agencies frequently impose conditions on the Company’s activities. These restrictions tend to become more stringent over time and can limit or prevent exploring for, finding and producing natural gas and oil on the Company’s Rockies leasehold. Certain environmental groups oppose drilling on some of Market Resources’ federal and state leases.

Various federal agencies within the U.S. Department of the Interior, particularly the Minerals Management Service and the Bureau of Indian Affairs, along with each Native American tribe, promulgate and enforce regulations pertaining to gas and oil operations on Native American tribal lands. These regulations include such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations. In addition each Native American tribe is a sovereign nation having the right to enforce laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Finally, lessees and operators conducting operations on tribal lands are generally subject to the Native American tribal court system. One or more of these factors may increase the Company’s costs of doing business on Native American tribal lands and have an impact on the viability of its gas, oil and transportation operations on such lands.

Both Questar Pipeline and Questar Gas incur significant costs to comply with federal pipeline-safety regulations. Questar may also be affected by possible future regulations requiring the tracking, reporting and reduction of greenhouse-gas emissions.

FERC regulates interstate transportation of natural gas. Questar Pipeline’s natural gas transportation and storage operations are regulated by the FERC under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The FERC has authority to: set rates for natural gas transportation, storage and related services; set rules governing business relationships between the pipeline subsidiary and its affiliates; approve new pipeline and storage-facility construction; and establish policies and procedures for accounting, purchase, sale, abandonment and other activities. FERC policies may adversely affect Questar Pipeline profitability. The FERC also has various affiliate rules that may cause the Company to incur additional costs of compliance.

State agencies regulate the distribution of natural gas. Questar Gas natural gas-distribution business is regulated by the PSCU and the PSCW. These commissions set rates for distribution services and establish policies and procedures for services, accounting, purchase, sale and other activities. PSCU and PSCW policies may adversely affect Questar Gas profitability.

Questar is dependent on bank credit facilities and continued access to capital markets to successfully execute its operating strategies.  The Company relies on bank borrowing and access to public capital markets to finance a material portion of its operating strategies. Also, Questar relies on access to short-term commercial paper markets. The Company is dependent on these capital sources to provide capital to acquire and develop properties. The availability and cost of these credit sources is cyclical, and these capital sources may not remain available or the Company may not be able to obtain money at a reasonable cost in the future. All Questar’s bank loans are floating-rate debt. From time to time the Company may use interest rate derivatives to fix the rate on a portion of its variable rate debt. The interest rates on bank loans are tied to debt credit ratings of Questar and its subsidiaries published by Standard & Poor's and Moody's. A downgrade of credit ratings could increase the interest cost of debt and decrease future availability of money from banks and other sources. Management believes it is important to maintain investment grade credit ratings to conduct the Company’s businesses, but may not be able to keep investment grade ratings.

General economic and other conditions impact Questar’s results.  Questar’s results may also be negatively affected by: changes in general economic conditions; changes in regulation; availability and economic viability of gas and oil properties for sale or exploration; creditworthiness of counterparties; rate of inflation and interest rates; assumptions used in business combinations; weather and natural disasters; changes in customers' credit ratings; competition from other forms of energy, other pipelines and storage facilities; effects of accounting policies issued periodically by accounting standard-setting bodies; terrorist attacks or acts of war; changes in business or financial condition; changes in credit ratings; and availability of financing for Questar.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 2.  PROPERTIES.

Questar E&P and Wexpro

Reserves – Questar E&P. The following table sets forth Questar E&P's estimated proved reserves, the estimated future net revenues from the reserves and the standardized measure of discounted net cash flows as of December 31, 2005. The estimates were collectively prepared by Ryder Scott Company, Netherland, Sewell & Associates, Inc. and H. J. Gruy and Associates, Inc., independent reservoir-engineering consultants. Questar E&P does not have any long-term supply contracts with foreign governments or reserves of equity investees or of subsidiaries with a significant minority interest. All reported reserves are located in the United States.

(1)

Estimated future net revenue represents estimated future gross revenue to be generated from the production of proved reserves, using average year-end 2005 prices of $7.80 per Mcf for natural gas and $56.47 per bbl for oil and NGL combined, net of estimated production and development costs (but excluding the effects of general and administrative expenses; debt service; depreciation, depletion and amortization; and income tax expense).

(2)

The standardized measure of discounted future net cash flows prepared by the Company represents the present value of estimated future net revenues after income taxes, discounted at 10%.

Estimates of proved reserves and future net revenues are made at year-end, using sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the remaining life of the properties (except to the extent a contract specifically provides for escalation). Year-end prices do not include the effect of hedging. Estimated quantities of proved reserves and future net revenues are affected by natural gas and oil prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating natural gas and oil reserves and their estimated values, including many factors beyond the control of the Company.

Questar E&P’s reserve statistics for the years ended December 31, 2003 through 2005, are summarized below:

Proved Gas and Oil Reserves (Bcfe)*

Year

Year-End Reserves

Annual Production

Reserve Life (Years)

2003

1,158.7

  92.8

12.5

2004

1,434.0

103.5

13.9

2005

1,480.4

114.2

13.0

*Does not include cost-of-service reserves managed, developed and produced by Wexpro for Questar Gas.

In 2005 gas and oil reserves increased 3%, after production and sales of producing properties, to 1,480.4 Bcfe versus a 24% increase in 2004 to 1,434.0 Bcfe. Questar E&P’s production replacement ratio was 141% in 2005 and 366% in 2004. Net reserve additions, revisions, purchases and sales in place totaled 160.6 Bcfe in 2005 and 378.8 Bcfe in 2004. Questar E&P’s five-year average finding cost of proved reserves per Mcfe was $1.08, $0.83 and $0.84 in 2005, 2004 and 2003, respectively.

Finding costs measure the costs of finding, developing and acquiring new proved reserves. The production replacement ratio measures company success at replacing production during a specific period. If the production replacement ratio is greater than 100%, the Company added or replaced more reserves than it produced for the same period. These non-GAAP measures provide useful information to investors interested in analyzing Questar’s performance, but may not be directly comparable with similar information disclosed by other gas and oil companies.

Questar E&P’s proved reserves by major operating areas at December 31, 2005 and 2004 follow:

Reserves – Cost-of-Service. The following table sets forth Questar Gas’s estimated cost-of-service proved natural gas reserves, which are managed, developed and produced by Wexpro under the terms of the settlement agreement; and Wexpro’s proved oil reserve, the estimates were made by Wexpro's reservoir engineers as of December 31, 2005. All reported reserves are located in the United States.

The gas reserves operated by Wexpro are delivered to Questar Gas at cost of service. Net income from oil properties remaining after recovery of expenses and Wexpro’s contractual return on investment under the settlement agreement is divided between Wexpro and Questar Gas. Therefore, SEC guidelines with respect to standard economic assumptions are not applicable. The SEC anticipated such potential difficulty and provides that companies may give appropriate recognition to differences arising because of the effect of the ratemaking process. Accordingly, Wexpro’s reservoir engineers used a minimum producing rate or maximum well-life limit to determine the ultimate quantity of reserves attributable to each well.

Reference should be made to Note 17 of the consolidated financial statements included in Item 8 in Part II of this Annual Report for additional information pertaining to both Questar E&P’s proved reserves and the Company’s cost-of-service reserves as of the end of each of the last three years.

In addition to this filing, Questar E&P and Wexpro will each file estimated reserves as of December 31, 2005, with the Energy Information Administration in the Department of Energy on Form EIA-23. Although the companies use the same technical and economic assumptions when they prepare the EIA-23, they are obligated to report reserves for all wells they operate, not for all wells in which they have an interest, and to include the reserves attributable to other owners in such wells.

Production.  The following table sets forth the net production volumes, the average sales prices per Mcf of gas, per barrel of oil and NGL produced, and the production cost per Mcfe for the years ended December 31, 2005, 2004 and 2003, respectively. Production costs include direct lifting costs (labor, repairs and maintenance, materials, supplies and workovers), administrative costs of production offices, insurance and property and severance taxes, but are exclusive of depreciation and depletion applicable to capitalized-lease acquisitions, exploration and development expenditures.

Productive Wells. The following table summarizes Market Resources' productive wells (including the cost-of-service wells managed by Wexpro) as of December 31, 2005. All of these wells are located in the United States.

  Gas

Oil

Total

Productive Wells

Gross

4,215.0

950.0

5,165.0

Net

1,953.9

450.1

2,404.0

Although many Market Resources wells produce both gas and oil, a well is categorized as either a gas or an oil well based upon the ratio of gas to oil produced. Each gross well completed in more than one producing zone is counted as a single well. At the end of 2005, there were 90 gross wells with multiple completions.

Market Resources also holds numerous overriding-royalty interests in gas and oil wells, a portion of which is convertible to working interests after recovery of certain costs by third parties. After converting to working interests, these overriding-royalty interests will be included in Market Resources' gross and net-well count.

Leasehold Acres. The following table summarizes developed and undeveloped-leasehold acreage in which Market Resources owns a working interest as of December 31, 2005. “Undeveloped Acreage” includes leasehold interests that already may have been classified as containing proved undeveloped reserves; and unleased mineral-interest acreage owned by the company. Excluded from the table is acreage in which Market Resources' interest is limited to royalty, overriding-royalty and other similar interests. All leasehold acres are located in the U.S.

Leasehold Acreage – December 31, 2005

    Developed (1)

 Undeveloped (2)

   Total

  Gross

Net

Gross

Net

Gross

Net

   Arizona

480

450

480

450

   Arkansas

32,049

10,310

3

1

32,052

10,311

   California

25

2

1,293

192

1,318

194

   Colorado

166,885

120,695

194,147

103,303

361,032

223,998

   Idaho

44,175

10,643

44,175

10,643

   Illinois

172

39

14,207

3,949

14,379

3,988

   Indiana

1,890

702

1,890

702

   Kansas

30,302

13,397

16,880

3,843

47,182

17,240

   Kentucky

17,323

6,669

17,323

6,669

   Louisiana

12,634

11,397

1,246

1,126

13,880

12,523

   Michigan

89

8

6,240

1,262

6,329

1,270

   Minnesota

313

104

313

104

   Mississippi

2,904

1,922

965

399

3,869

2,321

   Montana

20,149

8,535

301,379

53,279

321,528

61,814

   Nevada

320

280

680

543

1,000

823

   New Mexico

78,073

54,288

38,462

17,690

116,535

71,978

   North Dakota

4,634

546

146,364

21,781

150,998

22,327

   Ohio

202

43

202

43

   Oklahoma

1,502,162

267,650

83,081

49,927

1,585,243

317,577

   Oregon

43,869

7,671

43,869

7,671

   South Dakota

204,398

107,829

204,398

107,829

   Texas

144,467

60,037

57,651

43,799

202,118

103,836

   Utah

103,045

85,671

226,299

109,665

329,344

195,336

   Washington

26,631

10,149

26,631

10,149

   West Virginia

969

115

969

115

   Wyoming

237,278

152,713

403,661

259,524

640,939

412,237

      Total

2,336,157

787,605

1,831,839

814,543

4,167,996

1,602,148

(1)

Developed acreage is acreage spaced or assignable to productive wells.

(2)

Undeveloped acreage is leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

A portion of the leases summarized in the preceding table will expire at the end of their respective primary terms unless the existing leases are renewed or production has been obtained from the acreage subject to the lease prior to that date. In that event, the lease will remain in effect until production ceases. The following table sets forth the gross and net acres subject to leases summarized in the preceding table that will expire during the periods indicated:

Drilling Activity.  The following table summarizes the number of development and exploratory wells drilled by Market Resources, including the cost-of-service wells drilled by Wexpro, during the years indicated.

Gas Management

Gas Management owns 1,381 miles of gathering lines in Utah, Wyoming, Colorado and Oklahoma. In conjunction with these gathering facilities, Gas Management owns compression facilities, field-dehydration and measuring systems. Gas Management is a 50% partner in Rendezvous, which owns an additional 221 miles of gathering lines and associated field equipment.

Gas Management owns processing plants that have an aggregate capacity of 424 MMcf of unprocessed natural gas per day.

Energy Trading

Energy Trading, through its wholly owned subsidiary Clear Creek Storage Company, LLC, owns and operates an underground gas-storage reservoir in southwestern Wyoming.

Questar Pipeline

Questar Pipeline has a maximum capacity of 3,399 Mdth per day and firm-capacity commitments of 1,920 Mdth per day. Questar Pipeline's transmission system includes 2,499 miles of transmission lines that interconnect with other pipelines. Its core system includes two segments, often referred to as the northern system and southern system. The northern system extends from northwestern Colorado through southwestern Wyoming into northern Utah, while the southern system extends from western Colorado to Goshen, Utah. The transmission mileage includes lines at storage fields and tap lines used to serve Questar Gas, the 488 miles of the Southern Trails system in service that is owned by a subsidiary, and the 88 miles of Overthrust Pipeline that is owned by a subsidiary. The maximum-daily-capacity figures included above for Southern Trails and Overthrust are 88 Mdth and 1,119 Mdth, respectively. Questar Pipeline's system ranges in size from lines that are less than four inches in diameter to the Overthrust line that is 36 inches in diameter. Southern Trails also owns 210 miles of pipeline comprising the California segment of the Southern Trails system, although this segment has not been placed in service. Questar Pipeline has major compression sites, including a complex near Rock Springs, Wyoming, that compress gas volumes from the transmission system for delivery to other pipelines, including systems that move gas volumes east.

Questar Pipeline also owns the Clay Basin storage facility in northeastern Utah, that has a certificated capacity of 117.5 Bcf, including 53.5 Bcf of working gas, and several smaller storage aquifers in northeastern Utah and western Wyoming. Through a subsidiary, Questar Pipeline owns a processing plant in Price, Utah, and related gathering lines.

Questar Gas

Questar Gas distributes gas to customers in the major populated area of Utah, commonly referred to as the Wasatch Front, including the metropolitan Salt Lake area, Provo, Park City, Ogden, and Logan. It also serves customers throughout the state, including the cities of Price, Roosevelt, Vernal, Moab, Monticello, Fillmore, Cedar City and St. George. Questar Gas supplies natural gas to the southwestern Wyoming communities of Rock Springs, Green River, Evanston, Kemmerer and Diamondville and the southeastern Idaho community of Preston. To supply these communities Questar Gas owns and operates distribution systems and has a total of 24,709 miles of street mains, service lines and interconnecting pipelines. Questar Gas has a major operations center in Salt Lake City, Utah, and has operations centers, field offices and service-center facilities through other parts of its service area.

ITEM 3.  LEGAL PROCEEDINGS.

Questar is involved in a variety of pending legal disputes involving commercial litigation arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims. While the ultimate outcome and impact on Questar cannot be predicted with certainty, management believes that the outcome of these cases will not have a material adverse effect on financial position, operating results or liquidity.

Grynberg.  Questar affiliates are involved in various pending lawsuits filed by Jack Grynberg, an independent producer. The only active case, United States ex rel. Grynberg v. Questar Corp., Civil No. 99-MD-1604, consolidated as In re Natural Gas Royalties Qui Tam Litigation, Consolidated Case MDL No. 1293 (D. Wyo.) involves qui tam claims filed by Grynberg under the federal False Claims Act and is substantially similar to the other cases filed against pipelines and their affiliates that have been consolidated for discovery and pre-trial motions in Wyoming's federal district court. The cases involve allegations of industry-wide mismeasurement of natural gas quantities on which royalty payments are due the federal government

The defendants filed a motion contending that the court has no jurisdiction over the case because Grynberg cannot satisfy the statutory requirements for jurisdiction. The defendants argued Grynberg’s allegations were publicly disclosed prior to the filing of his complaint and Grynberg is not the “original source” of the information on which the allegations are based. The Special Master appointed in the case issued a Report and Recommendation to the district court recommending dismissal of the Questar defendants, except for one small entity acquired by Questar Gas after these cases were filed. The district court heard arguments on whether to adopt the Special Master’s Report on December 9, 2005. The district court has not issued a decision. Management is unable to determine a reasonable range of loss, if any, related to this matter.

Kansas Cases.  Energy Trading is a named defendant in cases pending in a Kansas state district court, Price v. Gas Pipelines, No. 99 C 30 (Dist. Ct. Kan.) and Price v. El Paso Entities, No. 03 C 23 (Dist. Ct. Kan.). These cases are similar to the cases filed by Grynberg, but the allegations of a conspiracy by the pipeline industry to set standards that result in the systematic undermeasurement of natural gas volumes and resulting underpayment of royalties are made on behalf of private lessors rather than on behalf of the federal government. The purported class involves all royalty owners of production from private land in Kansas, Wyoming and Colorado. Energy Trading opposes certification of the class and contends that it is not engaged in any gas measurement activities in Kansas. A hearing on plaintiffs’ motion to certify the class was held on April 1, 2005. The court has not issued a ruling in the case.

Beaver Gas Pipeline System.  On April 8, 2005, Kaiser-Francis appealed the trial judge’s order granting Questar E&P’s motion to dismiss the lawsuit filed against it in Kaiser-Francis Oil v. Anadarko Petroleum Corp., Case No. CJ-2003-66518 (Dist. Ct. Okla.). Kaiser-Francis was a co-defendant of Questar E&P in a prior Oklahoma case, Bridenstine v. Kaiser-Francis Oil Co . The original lawsuit was a class action alleging improper royalty payments for wells connected to the Beaver Gas Pipeline System in western Oklahoma which is no longer owned by Questar. Questar E&P and Anadarko (as the successor to another company) settled the lawsuit in December 2000 by agreeing to pay a total sum of $22.5 million, of which $16.5 million was allocated to Questar E&P. Kaiser-Francis chose not to settle and was assessed damages, including punitive damages, by a jury. Kaiser-Francis ultimately settled for $82.5 million, plus interest. As part of the settlement, Kaiser-Francis and the plaintiff class agreed to entry of a “superseding judgment” purporting to vacate the punitive damages award against Kaiser-Francis after the Oklahoma Supreme Court had affirmed that award and issued its mandate. Questar E&P and Anadarko have appealed the entry of the superseding judgment to the Oklahoma Supreme Court.

Kaiser-Francis’ current lawsuit claims that Questar E&P and Anadarko were obligated by express and implied indemnities to pay for a portion of the damages assessed in the jury trial and for its legal-defense costs. In dismissing the lawsuit for failure to state a claim, the district judge noted that the jury determined that Kaiser-Francis was involved in a conspiracy to commit fraud and was therefore barred by a doctrine similar to “unclean hands” from seeking indemnity for the judgment. On appeal, Kaiser-Francis contends that it should be allowed to amend its petition to argue that the superseding judgment shields it from the jury’s findings of wrongdoing. In dismissing the case, the trial judge found that the superseding judgment made no difference.  

Consonus Cases. Consonus, its parent company (Questar InfoComm) and certain named officers and directors of Consonus were named as defendants in a lawsuit, Melnyk v. Consonus, Inc., Case No. 2:03-CV-00528DB, pending in a federal district court. The plaintiffs’ are former minority shareholders who include a former officer and a former director and officer. They claim that the majority shareholders breached their fiduciary duties to minority shareholders by wasting assets and engaging in related-party transactions to the detriment of minority shareholders. Plaintiffs allege that they received an inadequate price for their shares in a statutory merger that occurred in mid-2003. A federal district judge, by an order dated January 26, 2006, dismissed this action with prejudice finding that plaintiffs’ claims were without merit. The case is pending appeal before the Tenth Circuit Court of Appeals. Questar has sold the Consonus assets.

Environmental Matters.  

Questar Pipeline received a Notice of Violation from the Colorado Department of Public Health and Environment, Air Pollution Control Division (APCD) dated February 3, 2005, concerning its operation of a tank battery in Rio Blanco County, Colorado. Specifically, the Colorado agency alleged that Questar Pipeline violated applicable environmental regulations by failing to obtain the necessary permits and complying with the best available control technology. Questar Pipeline has reached a settlement with APCD to resolve the Notice of Violation by entering into a consent order requiring the payment of $319,000 and undertaking a supplemental environmental project with an economic value of $340,000.

In 2004, the Environmental Protection Agency (EPA) issued two separate compliance orders alleging that Gas Management did not comply with regulatory requirements adopted to enforce the federal Clean Air Act. Both orders involved facilities in the Uinta Basin of eastern Utah that were purchased by Questar E&P in mid-2001. Gas Management is currently operating the facilities and filing necessary reports in compliance with regulatory requirements. It is discussing the allegations with the EPA and expects that it may be required to pay a civil penalty in excess of $100,000 in conjunction with each order. Potential regulatory violations associated with the timeliness of permit filings for other Gas Management facilities in the Uinta Basin have now been added to the civil penalty discussions with the EPA. These potential violations may yield additional civil penalties of an unknown amount.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

The Company did not submit any matters to a vote of stockholders during the last quarter of 2005.

PART II

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Information concerning the market for the common equity of the Company and the dividends paid on such stock is located in Note 16 to the consolidated financial statements included in Item 8 in Part II of this Annual Report. As of February 1, 2006, Questar had 9,798 shareholders of record.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities.

The following table sets forth the Company’s purchases of common stock registered under Section 12 of the Exchange Act that occurred during the quarter ended December 31, 2005.

*The numbers include shares purchased in conjunction with tax-payment elections under the Company’s Long-term Stock Incentive Plan. They exclude any fractional shares purchased from terminating participants in Questar’s Dividend Reinvestment and Stock Purchase Plan and any shares of restricted stock forfeited when failing to satisfy vesting conditions.

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION.

SUMMARY

Questar reported net income of $325.7 million, or $3.74 per diluted share, in 2005 compared to $229.3 million, or $2.67 for 2004 and $173.6 million or $2.06 in 2003. Net income in 2003 was reduced by $5.6 million, or $0.07 per share, due to the cumulative effect of implementing SFAS 143, a new accounting rule governing the treatment of retirement costs of long-lived assets. Following is a comparison of net income by lines of business:

Market Resources’ net income increased 56% in 2005 compared to 2004 and 43% in 2004 over 2003. Primary factors for the higher income were increases in production, higher realized natural gas, oil and NGL prices, increased gas-gathering and processing volumes and margins, and additions to Wexpro’s investment base. The cumulative effect of implementing SFAS 143 reduced Market Resources 2003 earnings by $5.1 million.

Questar Pipeline reported net income of $24.4 million in 2005 compared to $27.6 million in 2004. Increased transportation capacity commitments and higher NGL sales prices drove 6% revenue growth. In 2005, Questar Pipeline recorded a $10.4 million after-tax asset impairment for the California segment of the company’s Southern Trails Pipeline. Questar Pipeline earned $27.6 million in 2004 compared with $30.2 million in 2003. The 2004 results were lower by $3.0 million after tax as a result of an order to credit to transportation customers certain revenues from the sale of liquids recovered from gas processing. A more-detailed discussion of the FERC decision follows. The cumulative effect of implementing SFAS 143 reduced Questar Pipeline 2003 net income by $133,000.

Questar Gas net income increased 14% in 2005 versus 2004 and increased 56% in 2004 versus 2003. Higher 2005 revenues resulted from a record addition of 30,330 customers. Questar Gas 2005 net income increased $3.0 million with the PSCU approval of a gas-processing settlement agreement. The 2003 results were negatively impacted by a $15.5 million after-tax charge for refund of disputed gas-processing costs, of which $11.9 million related to periods prior to 2003. The cumulative effect of implementing SFAS 143 reduced Questar Gas 2003 earnings by $334,000.

Net income from corporate and other operations increased $2.2 million in 2005 compared with 2004 because of higher net interest income and income tax benefits. In 2004, a reorganization of information-technology assets shifted activities to other business units resulting in a $2.4 million decline in net income compared with 2003.

RESULTS OF OPERATION

Market Resources

Market Resources operates through four principal subsidiaries. Questar E&P acquires, explores for, develops and produces natural gas, oil, and NGL; Wexpro manages, develops and produces cost-of-service reserves for affiliated company, Questar Gas; Gas Management provides midstream field services including natural gas-gathering and processing services for affiliates and third parties; and Energy Trading markets equity and third-party gas and oil, provides risk-management services, and through its wholly owned limited liability company, Clear Creek Storage Company, LLC, owns and operates an underground natural gas-storage reservoir.

Market Resources Consolidated Results

Market Resources net income for 2005 was $258.2 million compared with $165.4 million in 2004, a 56% increase, and $116.0 million in 2003. Operating income increased $148.7 million, or 54%, in the year to year comparison due to higher commodity prices and increased natural gas production at Questar E&P, an increased investment base at Wexpro, and increased NGL volumes coupled with improved gas gathering and processing margins at Gas Management. Following is a summary of Market Resources’ financial and operating results:

Questar E&P

Questar E&P net income increased 60% to $172.8 million in 2005 compared with $108.2 million in 2004 and $70.4 million in 2003. The increases were driven by a combination of higher realized natural gas, oil and NGL prices and increased gas, oil and NGL production volumes.

Questar E&P’s production increased to 114.2 Bcfe in 2005, a 10% increase compared to the year-earlier period. Natural gas is Questar E&P’s primary focus. On an energy-equivalent basis, natural gas comprised approximately 88% of Questar E&P’s production for 2005. A comparison of energy equivalent production by region is shown in the following table:

Questar E&P production from the Pinedale Anticline in western Wyoming increased 41%

 In 2005 and comprised 29% of Questar E&P total production for the year. Questar E&P completed 40 new wells at Pinedale during 2005.

In the Uinta Basin of eastern Utah, Questar E&P production increased 3% to 25.6 Bcfe in 2005 compared to 24.8 Bcfe a year ago despite production constraints related to third quarter construction and maintenance on an interstate pipeline that serves the area.

Production from Questar E&P’s Rockies Legacy properties in 2005 was 16.7 Bcfe compared to 18.0 Bcfe during the 2004 period, a 7% decrease. Legacy properties include all of Questar E&P’s Rocky Mountain producing properties other than Pinedale and the Uinta Basin. Production during the 2005 period was negatively impacted by normal field decline, seasonal restrictions that limit access to leases and wells during the winter months, payout of a high-volume well that reduced the company’s working interest and mechanical problems that delayed completion of a new well in the Vermillion Basin.

Midcontinent production was 38.7 Bcfe in 2005 compared to 37.2 Bcfe for the same period of 2004, a 4% increase. The company continued one-rig-development programs in both the Hartshorne coalbed-methane development project in the Arkoma Basin of eastern Oklahoma and the ongoing infill-development drilling on the Elm Grove properties in northwest Louisiana.

Questar E&P also benefited from higher realized prices for natural gas, oil and NGL. In 2005 the weighted average realized natural gas price for Questar E&P (including the effects of hedging) was $5.18 per Mcf compared to $4.18 per Mcf in 2004, a 24% increase. Realized oil and NGL prices for 2005 averaged $41.54 per bbl compared with $30.97 per bbl during the prior year period, a 34% increase. A comparison of average realized prices by region, including hedges, is shown in the following table:

Approximately 83% of Questar E&P’s gas production in 2005 was hedged or pre-sold compared to 76% in 2004. Hedging reduced gas revenues $173.9 million in 2005 and $83.9 million in 2004. Questar E&P also hedged or pre-sold approximately 70% of its 2005 oil production and 66% of its 2004 production. Oil hedges reduced revenues $24.8 million in 2005 and $16.3 million in 2004.

Questar may hedge up to 100 percent of its forecasted production from proved reserves to lock in acceptable returns on invested capital and to protect cash flow and earnings from a decline in commodity prices. During 2005, Questar E&P continued to take advantage of high natural gas and oil prices to add to hedge additional production in 2006, 2007 and 2008. Natural gas and oil hedges as of December 31, 2005, are summarized in Item 7A of Part I of this Annual Report.

Questar E&P’s controllable production cost structure per unit of production (the sum of depreciation, depletion and amortization expense, lease operating expense, general and administrative expense and allocated interest expense) increased 9% to $2.23 per Mcfe in 2005 versus $2.05 per Mcfe in 2004 and $1.99 per Mcfe in 2003. Questar E&P’s controllable production cost structure is summarized in the following table:

Depreciation, depletion and amortization expense rose 13% in 2005 to $1.18 per Mcfe due to the ongoing depletion of older, lower-cost reserves, reserve revisions for the company’s Uinta Basin properties and higher reserve replacement (finding and development) costs. Higher day rates for rigs and other services in core operating areas, along with sharply higher steel prices, resulted in higher drilling and completion costs.  

Production taxes per Mcfe produced were $0.60, $0.46 and $0.34 in 2005, 2004 and 2003, respectively. Increased production taxes were driven by higher gas, oil and NGL sales prices. Most production taxes are based on a fixed percentage of commodity sales prices. Higher lease operating expenses reflect a general increase in well service costs, including costs of contracted services and production-related supplies, increased workover and production enhancement projects and additional production-related costs.

Exploration expense increased $1.9 million in 2005 compared to the 2004. The expense increase was due to increased exploratory seismic acquisition expenditures in the Midcontinent and Uinta Basin.

Questar E&P abandonment and impairment expense declined $5.3 million in 2005 compared to 2004. The 2004 amount included $2.3 million of expense due to a well with collapsed casing.

Pinedale Anticline Drilling Activity

As of December 31, 2005, Market Resources operated and had an interest in 144 producing wells on the Pinedale Anticline compared to 104 and 76 at year-end 2004 and 2003, respectively. In August, 2005, the Wyoming Oil and Gas Conservation Commission (WOGCC) approved 10-acre-density drilling for Lance Pool (combined Lance and Mesaverde formations) wells on about 12,700 acres of Market Resources’ 18,208 acre (gross) Pinedale leasehold. The area approved for increased density corresponds to the currently estimated productive limits of Market Resources’ core acreage in the field. On 10-acre density, the company has over 932 potential Lance Pool well locations at Pinedale. Of the 788 locations yet to be drilled, 203 were booked as proved undeveloped at year-end, leaving over 585 locations unbooked. Questar E&P has an average Lance Pool working interest of 59.4% and an average net revenue interest of 47.5% in 873 of the 932 locations. Wexpro has an average Lance Pool working interest of 51.3% in 215 of the 932 locations, resulting in a combined average Lance Pool working interest for Questar E&P and Wexpro of 67.5% in the 932 locations.

On August 19, 2005, Questar E&P reached a total depth of 19,520 feet in the Hilliard Shale at the Stewart Point 15-29 exploratory well. Based on log information and gas shows, Questar E&P identified multiple zones of interest below the Lance Pool at depths from about 16,000 to 19,500 feet, ran casing to total depth and in mid-September commenced hydraulic stimulation and testing. Starting in the lower part of the well, the company pumped three frac stages over a 900 foot interval from 18,541 to 19,434 feet and began flowing the well back to sales on an 18/64 inch choke. During initial flowback, the company measured extrapolated flow rates as high as 10.7 MMcf per day of dry, sweet gas with 10,000 to 12,000 psig flowing casing pressure and an extrapolated rate of about 2,400 barrels per day of frac water. As the flowback continued, the well exhibited steadily declining rates and pressures and, on several occasions, had to be shut in to remove debris plugging the choke. Eventually a combination of very small pieces of shale from the formation, proppant used in the fracs, and chunks of the flow-through frac plugs used to isolate individual stages partially filled the wellbore, blocking the flow of gas to the surface. The vertical extent of the obstruction is currently unknown. . Given the very high formation pressures, specialized equipment (a high-pressure snubbing unit) and experienced personnel are required to attempt to circulate out the obstruction inside the wellbore and either reestablish production from the initial test interval, or isolate that interval and move up hole to test additional zones. The company was not able to secure the right snubbing unit and crew for this operation before cold winter weather would make this operation technically and operationally risky. The resumption of testing of the well will be delayed until the spring of 2006.

Uinta Basin

During 2005, the company drilled or participated in ten horizontal Green River formation oil wells, 54 Wasatch and Upper Mesaverde gas wells, and five deeper Blackhawk and Mancos formation gas wells on its core acreage block.

In December, 2005 Questar E&P completed the Wolf Flat 1P-1-15-19 well, the first well drilled under an Exploration and Development Agreement (EDA) with the Ute Indian Tribe covering 12,557 acres of tribal minerals in the southern Uinta Basin. Questar E&P has a 50% working interest in the Wolf Flat well. The company also completed acquisition of a 2-D seismic survey covering a portion of the EDA lands and exercised its option to acquire leases on all of the EDA lands. The Ute Indian Tribe has the option to participate in the first well drilled in each section with up to a 50% working interest. On December 31, 2005, the company’s second 100% working interest test well in the Flat Rock prospect located one mile north of the Wolf Flat well, the FR 1P-36-14-19 well, was waiting on completion.

Rockies Legacy

In the Vermillion Basin on the southwestern Wyoming-northwestern Colorado border, Market Resources continues to evaluate the potential of several formations at depths of 10,000 to 15,000 feet under the company’s 143,000 net leasehold acres. As of December 31, 2005, the company had recompleted two older wells, drilled and completed three new wells and was drilling one well, the Canyon Creek 47. The first new well, Alkali Gulch Unit Well No 1, was completed in June 2005 and produced an average of 1.68 MMcf per day from the Baxter, Frontier and Dakota formations during the first 206 days. On December 31, 2005, the well was producing about 1.05 MMcf per day. The second new well, Canyon Creek 41, went to sales on September 21, 2005. During the first 102 days of production, the well averaged about 2.0 MMcf per day from the Baxter and Frontier formations. The well was producing about 1.1 MMcf per day on December 31, 2005. After delays related to mechanical problems, the third new well, Hiawatha Deep Unit No. 5, was completed and turned to sales in mid-November, 2005. During the first 46 days of production, the well averaged 1.2 MMcf per day from the Baxter, Frontier and Dakota formations and was producing about .9 MMcf per day on December 31, 2005. The company currently plans to drill about 12 new wells in the Vermillion Basin during 2006 and has initiated the process with the Bureau of Land Management (BLM) for a new Environmental Impact Statement covering the potential development of the deeper objectives.

Midcontinent

During 2005, the company continued one-rig development programs at both the Hartshorne coalbed-methane project in the Arkoma Basin of eastern Oklahoma and the infill-development drilling project in the Elm Grove properties in northwestern Louisiana. The company drilled or participated in 38 new Hartshorne wells in 2005. In the Elm Grove area, the company drilled or participated in 31 new wells in 2005 and estimates that it has a remaining inventory of about 108 locations.

Wexpro

Wexpro’s 2005 net income was $43.7 million compared with $35.3 million in 2004 and $32.6 million in 2003. Wexpro develops and produces gas reserves on behalf of affiliate Questar Gas. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19% on its investment in commercial wells and related facilities – adjusted for working capital and reduced for deferred income taxes and depreciation (investment base). Wexpro invested $57.8 million, boosting its investment base 13% to $206.3 million at December 31, 2005, up $23.5 million over the year earlier. Wexpro’s 2005 net income also benefited from 35% higher realized oil and NGL prices.

Gas Management

Gas Management net income increased 70% to $35.7 million in 2005 from $21.0 million in 2004 and $13.3 million in 2003. Gross keep-whole processing margins (revenue from the sale of extracted NGLs less the cost of natural gas to replace the Btu-equivalent of extracted NGL volumes) grew 22% from $14.2 million in 2004 to $17.4 million in 2005. The first quarter 2005 acquisition of a gas plant in western Wyoming drove a 59% increase in extracted NGL volumes in 2005 versus the year earlier. Gathering volumes increased 32.3 million MMBtu to 257.0 million MMBtu in 2005 due primarily to expanding Pinedale production and new projects serving third parties in the Uinta Basin.

To reduce processing margin risk, Gas Management has restructured a number of its processing agreements with producers from “keep-whole” contracts to “fee-based” contracts. (A keep-whole contract protects producers from frac spread risk, while fee-based contracts eliminate commodity price risk for the plant owner.) To further reduce margin volatility associated with keep-whole contracts, Gas Management began managing NGL price risk in 2004 by using forward-sales contracts. In 2005 keep-whole contracts benefited from a 19% increase in NGL sales prices versus the prior-year. Fee-based contracts benefited from a $0.02 increase in the rate charged per MMBtu processed in 2005. Forward sales contracts decreased NGL revenues by $1.0 million in 2005.

Earnings before tax from Gas Management’s 50% interest in Rendezvous increased to $7.2 million in 2005 versus $5.0 million for 2004, a 45% increase. Earnings growth in Rendezvous was driven by increased gathering volumes. Rendezvous provides gas gathering services for the Pinedale and Jonah producing areas. Gas Management continues to invest in additional gas gathering and processing and liquids-handling facilities to serve growing equity and third-party production in its core areas of the Pinedale and Jonah fields in western Wyoming and the Uinta Basin in eastern Utah.

During the first quarter of 2005, Gas Management acquired a cryogenic gas processing facility located approximately 13 miles south of Gas Management’s Blacks Fork plant, adding approximately 60 MMcf per day of raw gas processing and NGL extraction capacity at its western Wyoming hub. The plant has been connected to the Blacks Fork/Granger complex to significantly enhance processing and blending capacity for Pinedale, Jonah and other western Wyoming producers served by Gas Management and Rendezvous.

Gas Management completed its condensate and produced-water gathering and transportation facilities on Market Resources’ Pinedale Anticline leasehold in November 2005 in time to satisfy BLM conditions for expanded winter access. These new facilities will eliminate over 25,500 tanker-truck trips per year at peak production from Market Resources’ operated acreage and the related air emissions, dust, noise, visual and traffic impacts.

Gas Management entered into an agreement with a third party producer to gather, compress and process gas in the Uinta Basin. Under terms of the fee-based agreement, the company constructed gas compression facilities and expanded its existing Red Wash gas plant to process an additional 70 MMcf per day of raw gas. The processed gas and liquids are redelivered to the producer. The new facilities were in service at the end of the third quarter 2005. Gas Management has also signed a letter of intent to form a joint venture with the Ute Indian Tribe and another industry participant to build a gas gathering system for the Flat Rock area in southern Uinta Basin.

Energy Trading

Energy Trading’s net income for 2005 was $6.0 million compared to $0.9 million in 2004 and a loss of $0.4 million in 2003. Gross margins for gas and oil marketing (gross revenues less costs for gas and oil purchases, transportation and gas storage) increased to $14.5 million in 2005 versus $6.8 million a year ago, a 113% increase. The increase in gross margin was due primarily to a 77% higher unit margin and a 21% increase in volumes (includes both equity and third-party) over the same period last year.

Questar Pipeline

Questar Pipeline provides FERC-regulated interstate natural gas transportation and storage and non-jurisdictional processing and gathering services. Following is a summary of Questar Pipeline’s financial and operating results:

Questar Pipeline’s net income was $24.4 million in 2005 compared with $27.6 million in 2004 and $30.2 million in 2003. The 2005 results were reduced by $10.4 million after tax for an impairment of the California segment of Southern Trails. Revenues increased in 2005 due to new transportation contracts and settlement of a liquids revenue sharing dispute with customers. See Note 2 to the consolidated financial statements included in Item 8 of Part II in this Annual Report for a discussion of the settlement.

Revenues

Gas transportation volumes increased 2005 over the prior year due to new transportation contracts. Following is a summary of major changes in Questar Pipeline’s revenues for 2005 compared with 2004 and 2004 compared with 2003:

#

Questar Pipeline has expanded its transportation system in response to growing regional natural gas production and transportation demand. Questar Pipeline added new transportation contracts in 2004 and 2005 for deliveries to the Kern River pipeline at Goshen, Utah. In the second quarter of 2005, Questar Pipeline began service to an electric generation facility in central Utah.

Questar Pipeline’s existing transportation system is nearly fully contracted. As of December 31, 2005, Questar Pipeline had firm-transportation contracts of 1,920 Mdth per day compared with 1,643 Mdth per day as of December 31, 2004. The increase was primarily due to a new contract of 190 Mdth per day to serve an electric generation facility and 102 Mdth per day for an expansion of its southern system. Questar Pipeline began partial service on this expansion in September 2005 and full service in November 2005. Questar Pipeline’s firm-transportation contracts had a weighted average remaining life of 10.9 years as of December 31, 2005.

Questar Gas is Questar Pipeline’s largest transportation customer with firm transportation contracts for 951 Mdth per day, including 50 Mdth per day for winter-peaking service. Most of these contracts extend through mid 2017.

Questar Pipeline owns and operates the Clay Basin underground gas storage facility, the largest in the region, with working gas capacity of 53.5 Bcf. This facility is 100% subscribed under long-term contracts. In addition to Clay Basin, Questar Pipeline also owns and operates three smaller aquifer gas storage facilities. Questar Pipeline’s firm storage contracts had a weighted average remaining life of 8.0 years as of December 31, 2005.

Questar Gas has contracted for 26% of firm-storage capacity at Clay Basin for terms extending from three to 14 years and 100% of the firm-storage capacity at the aquifer facilities for terms extending for 13 years.

Questar Pipeline transportation and storage rates are based on straight-fixed-variable rate design and approved by the FERC. All fixed costs of providing service including depreciation and return on investment are recovered through the demand charge. Fixed costs comprise about 95% of Questar Pipeline costs and are recovered through demand charges. Therefore, Questar Pipeline’s earnings are driven primarily by demand revenues from firm shippers. Variable operating costs based on throughput are recovered through volumetric charges. With straight-fixed variable rate design, period-to-period changes in firm-transportation volumes do not have a significant impact on earnings.

See Note 2 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for discussion of Questar Pipeline’s fuel-gas reimbursement percentage (FGRP) proceedings.

In addition to the changes in liquid revenues associated with the FGRP proceedings, 2005 liquid revenues increased $5.6 million over 2004 due to higher NGL prices and volumes.

Expenses

Operating, maintenance, general and administrative expenses were flat in 2005 compared with 2004 and increased 5% in 2004 compared with 2003. The increases were primarily due to higher labor and labor overhead costs offset by lower information technology and fuel gas costs. Operating, maintenance, general and administrative expenses per dth transported were $0.139 in 2005 compared with $0.156 in 2004 and $0.139 in 2003. Operating, maintenance, general and administrative expenses include processing and storage costs.

Depreciation expense increased 4% in 2005 over 2004 and 8% in 2004 over 2003 reflecting increased pipeline investment.

Clay Basin Storage

Questar Pipeline conducts periodic pressure tests on its Clay Basin storage facility. Beginning with a test in April 2002, the company noted a discrepancy between the book volumes of cushion gas at Clay Basin and the volumes implied by pressure data. Questar Pipeline retained a reservoir consultant to model the reservoir and determine the size and cause of the discrepancy. The company conducted additional pressure tests in April 2004, October 2004, April 2005 and October 2005 to validate the model.

The reservoir model indicates from 0 to 3.8 Bcf of gas may be missing from Clay Basin, with the most likely amount of 3.2 Bcf. The gas loss is due to a combination of cumulative imprecision inherent in natural gas measurement devices and reservoir heterogeneity that impacts storage reservoir performance. There is no indication that the reservoir is leaking. The Clay Basin reservoir is functioning as expected to meet customer requirements.

Questar Pipeline has proposed to the FERC that the loss of gas be recorded as a reduction of native gas remaining in the reservoir which would not impact Questar Pipeline net income. Alternatively, if the FERC requires Questar Pipeline to adjust recoverable cushion gas, earnings could be reduced by about $3 million after taxes.

Carbon Dioxide Processing Plant

Questar Transportation Services, a subsidiary of Questar Pipeline, owns non-jurisdictional gathering lines and a processing plant near Price, Utah. The plant was built in 1999 to process gas on behalf of Questar Gas. Questar Gas and other parties have contracted for the plant’s firm capacity and pay the cost of service for operating the plant.

Regulation

FERC Order No. 2004 requires employees engaged in transportation system operations to function independently from employees of marketing and energy affiliates. In addition a transportation provider must treat all transportation customers on a non-discriminatory basis and must not operate its transportation system to preferentially benefit its marketing or energy affiliates. Questar Pipeline has determined that all Market Resources subsidiaries except Gas Management are marketing or energy affiliates. Questar Gas is not an energy or marketing affiliate.

Questar Pipeline is required to comply with the Pipeline Safety Improvement Act of 2002. This Act and the rules issued by the DOT require interstate pipelines and local distribution companies to implement a 10-year program of risk analysis, pipeline assessment and remedial repair for transportation pipelines located in high-consequence areas such as densely populated locations. Questar Pipeline’s plan for complying with the Act was filed with the DOT during 2004. Questar Pipeline estimates that its annual cost to comply with the Act will be approximately $1 million, not including costs of pipeline replacement, if necessary.

See Note 2 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for a discussion of the Fuel Gas Reimbursement Percentage filings with the FERC.

Southern Trails Pipeline

See Note 4 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for discussion of the impairment of the California segment of Southern Trails.

Questar Gas

Questar Gas distributes natural gas in Utah, southwestern Wyoming and southeastern Idaho. Following is a summary of Questar Gas’s financial and operating results:

Questar Gas’s net income increased to $36.0 million in 2005 compared with $31.5 million in 2004 and $20.2 million in 2003. The 2003 results were reduced by a $15.5 million after tax charge for refund of disputed gas-processing costs, of which $11.9 million related to periods prior to 2003.

Margin Analysis

Questar Gas’s margin (revenues less gas costs) increased $14.3 million in 2005 compared with 2004, and $1.6 million in 2004 compared with 2003. Following is a summary of major changes in Questar Gas’s margin for 2005 compared to 2004 and 2004 compared to 2003:

Residential and commercial sales volumes increased 4% in 2005 compared with 2004 as increased customers and increased usage per customer offset the impact of warmer weather. At December 31, 2005, Questar Gas was serving 824,447 customers, a 3.8% increase over the prior year. Housing construction in Utah remained strong, driven by population growth and continuing low mortgage-interest rates. Usage per customer, adjusted for normal temperatures, was down 1% in 2005 compared with 2004 and down 3% in 2004 compared with 2003. Over the long term, usage per customer has been decreasing due to more efficient appliances and homes and customer response to higher prices.

Weather, as measured in degree days, was 3% warmer than normal in 2005 compared to 3% colder than normal in 2004 and 7% warmer than normal in 2003. A weather-normalization adjustment on customer bills generally offsets financial impacts of moderate temperature variations.

Industrial deliveries declined 14% in 2005 compared with 2004 and 10% in 2004 compared with 2003 primarily driven by lower power-generation requirements in the current period and customers changing to the residential and commercial rate schedules.

Expenses

Cost of natural gas sold increased 34% in 2005 compared with 2004 and 36% in 2004 compared with 2003 due to increased gas purchase costs and increased volumes. Questar Gas accounts for purchased-gas costs in accordance with procedures authorized by the PSCU and the PSCW. Purchased-gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes. As of December 31, 2005, Questar Gas had a $39.9 million balance in the purchased-gas adjustment account representing gas costs incurred but not yet recovered from customers. On November 1, 2005, Questar Gas increased Utah rates by 20% to cover higher costs of purchased natural gas. Combined with a 14% increase in June and other changes, customer rates at December 31, 2005 were 42% higher than the prior year. In February 2006, Questar Gas reduced rates by 8% to reflect forecasts of lower gas purchase prices.

Operating, maintenance, general and administrative expenses increased 8% in 2005 compared with 2004 and 4% in 2004 compared with 2003. The increases are due to higher labor and labor overhead costs and bad debt costs.

Depreciation expense increased 9% in 2005 compared with 2004 and 5% in 2004 compared with 2003 due to plant additions, including a customer information system that was placed in service in July 2004 and transfers of information technology assets from affiliates.

Rate-refund Obligation

See Note 2 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for a discussion of the regulatory proceedings involving Questar Gas’s processing costs.

Regulation

Questar Gas is subject to the requirements of the Pipeline Safety Improvement Act. Questar Gas estimates that it will cost $4.0 to $5.0 million per year to comply with the act, not including costs of pipeline replacement if necessary. The PSCU has allowed Questar Gas to record a regulatory asset for these incremental operating costs incurred to comply with this Act until the next rate case or 2007, whichever is sooner.

Corporate and Other Operations

Corporate and Other Operations include other services and activities. Revenues include sales to affiliates.

Revenues decreased 46%, operating and maintenance decreased 94%, general and administrative expense decreased 38% and depreciation decreased 61% in 2005 compared with 2004 due to the 2004 reorganization of information-technology-related businesses and the May 2005 sale of data-hosting assets. Questar reorganized its information-technology services in June 2004, resulting in a reduction of staff and $0.6 million of severance costs. The remaining information-technology assets and employees were transferred to affiliates. Revenues, operating and maintenances expense, depreciation and amortization decreased in 2004 compared with 2003 also as a result of the discussed reorganizations.

Consolidated Operating Results After Operating Income

Interest and Other Income

Interest and other income was higher in 2005 compared to 2004 as shown in the table below. Questar Gas’s return on gas stored underground increased because of higher rates and inventory valuations. The higher earnings also reflect interest received on hedging collateral deposits. Gains from asset sales added $4.7 million before tax in 2005.

Earnings from unconsolidated affiliates

Gas Management has a 50% interest in Rendezvous, which provides gas-gathering services for the Pinedale and Jonah producing areas of western Wyoming. Gas Management’s share of Rendezvous earnings before tax increased to $7.2 million in 2005 compared to $5.0 million in 2004. Rendezvous gathering volumes increased 47% in 2005 compared to 2004.

Interest expense

Interest expense rose in 2005 because the Company increased borrowings to meet hedging collateral calls precipitated by increases in natural gas and oil prices.

Income taxes

The effective combined federal and state income tax rate was 36.6% in 2005, 36.1% in 2004 and 36.4% in 2003.

Cumulative Effect of Accounting Change

On January 1, 2003, the Company adopted SFAS 143, “Accounting for Asset Retirement Obligations,” and recorded a cumulative effect that reduced net income by $5.6 million, or $0.07 per diluted common share.

LIQUIDITY AND CAPITAL RESOURCES

Operating Activities

Net cash provided from operating activities increased 20% in 2005 compared to 2004 and 33% in 2004 compared to 2003 due to higher net income and noncash adjustments to income.

Investing Activities

Capital spending in 2005 amounted $715.9 million. The details of capital expenditures in 2005 and 2004 and a forecast for 2006 are shown in the table below.

Market Resources

Market Resources’ expanded Rockies, Uinta Basin and Midcontinent drilling programs and construction of the water and condensate gathering system to serve the Pinedale Anticline represented the majority of the increase in capital expenditures for 2005 compared to 2004. Completion of the water and condensate gathering system in 2005 is the primary reason for the decrease in forecast 2006 capital expenditures.

In 2005 Market Resources increased drilling activity at Pinedale and in the Midcontinent region. During 2005 Market Resources participated in 501 wells (180.2 net), resulting in 171.3 net successful gas and oil wells and 8.9 net dry or abandoned wells. The net drilling-success rate was 95.1% in 2005. There were 103 gross wells in progress at year end. Market Resources also increased investment in its midstream gathering and processing-services business to expand capacity in both western Wyoming and eastern Utah in response to growing equity and third-party production volumes.

Questar Pipeline

During 2005, Questar Pipeline completed a new pipeline extension to a power plant in Mona, Utah, and completed a 102 MMdth per day expansion of its southern transportation system.

Questar Gas

During 2005, Questar Gas added 532 miles of main, feeder and service lines to provide service to 30,330 new customers.

Corporate and other operations

Net cash used in investing activities includes proceeds of $13.0 million from the second quarter 2005 sale of Consonus assets.

Financing Activities

Net cash flow provided from operating activities was sufficient to fund net capital expenditures in 2005. In the fourth quarter, the Company repaid $200 million borrowed in the third quarter on Market Resources’ revolving loan facility. In 2005, Questar Gas borrowed $50 million from a bank under a five-year loan agreement and used the proceeds to repay short-term debt.

Short-term debt amounted to $94.5 million at December 31, 2005, and was comprised of commercial paper with an average interest rate of 4.43%. A year earlier short-term debt amounted to $68.0 million and was comprised of commercial paper with an average interest rate of 2.45%. Questar’s commercial paper borrowings are backed by short-term line-of-credit arrangements. The Company had $420 million of short-term lines of credit at December 31, 2005.

Questar consolidated capital structure consisted of 41% combined short- and long-term debt and 59% common shareholders' equity at December 31, 2005 and 2004. Ratings of senior-unsecured debt as of December 31, 2005, were as follows:

Standard & Poor’s and Moody’s ratings were designated as stable.

The Company had negative net working capital at December 31, 2005, because of liabilities associated with out-of-the money energy-hedging derivatives.

Contractual Cash Obligations and Other Commitments

In the course of ordinary business activities, Questar enters into a variety of contractual cash obligations and other commitments. The following table summarizes the significant contractual cash obligations as of December 31, 2005.

Critical Accounting Policies, Estimates and Assumptions

Questar’s significant accounting policies are described in Note 1 to the consolidated financial statements included in Item 8 of Part II of this Annual Report. The Company's consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles. The preparation of consolidated financial statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. The following accounting policies may involve a higher degree of complexity and judgment on the part of management.

Successful Efforts Accounting for Gas and Oil Operations

The Company follows the successful efforts method of accounting for gas- and oil-property acquisitions, exploration, development and production activities. Under this method, the acquisition costs of proved and unproved properties, successful exploratory wells and development wells are capitalized. Other exploration costs, including geological and geophysical costs, the delay rental and administrative costs associated with unproved property and unsuccessful exploratory well costs, are expensed. Costs to operate and maintain wells and field equipment are expensed as incurred.

The capitalized costs of unproved properties are generally combined and amortized over the expected holding period for such properties. Individually significant unproved properties are periodically reviewed for impairment. Capitalized costs of unproved properties are reclassified as proved property when related proved reserves are determined or charged against the impairment allowance when abandoned.

Capitalized proved-property-acquisition costs are amortized by field using the unit-of-production method based on proved reserves. Capitalized exploratory-well and development costs are amortized similarly by field based on proved developed reserves. The calculation takes into consideration estimated future equipment dismantlement, surface restoration and property-abandonment costs, net of estimated equipment-salvage values. Other property and equipment are generally depreciated using the straight-line method over estimated useful lives or the unit-of-production method for certain processing plants. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production amortization rate would be significantly affected.

Questar E&P engages independent reservoir-engineering consultants to prepare estimates of the proved gas and oil reserves. Reserve estimates are based on a complex and highly interpretive process that is subject to continuous revision as additional production and development-drilling information becomes available.

Long-lived assets are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated on a field-by-field basis. If the undiscounted pretax cash flows are less than the net book value of the asset group, the asset value is written down to estimated fair value, which is determined using discounted future net revenues.

Accounting for Derivatives

The Company uses derivative instruments, typically fixed-price swaps, to hedge against a decline in the realized prices of its gas and oil production. Accounting rules for derivatives require that these instruments be marked to fair value at the balance-sheet reporting date. The change in fair value is reported either in net income or comprehensive income depending on the structure of the derivatives. The Company has structured virtually all energy-derivative instruments as cash-flow hedges as defined in SFAS 133 as amended. Changes in the fair value of cash-flow hedges are recorded on the balance sheet and in comprehensive income or loss until the underlying gas or oil is produced. When a derivative is terminated before its contract expires, the associated gain or loss is recognized in income over the life of the previously hedged production.

Revenue Recognition

Revenues are recognized in the period that services are provided or products are delivered. Questar E&P uses the sales method of accounting whereby revenue is recognized for all gas, oil and NGL sold to purchasers. Revenues include estimates for the two most recent months using published commodity index prices and volumes supplied by field operators. A liability is recorded to the extent that Questar E&P has an imbalance in excess of its share of remaining reserves in an underlying property. Energy-trading revenues are presented on a gross-revenue basis.

Questar Gas estimates revenues on a calendar basis even though bills are sent to customers on a cycle basis throughout the month. The company estimates unbilled revenues for the period from the date meters are read to the end of the month, using usage history and weather information. Approximately one-half month of revenues is estimated in any period. The gas costs and other variable costs are recorded on the same basis to ensure proper matching of revenues and expenses.

Questar Gas’s tariff provides for monthly adjustments to customer charges to approximate the impact of normal temperatures on nongas revenues. Questar Gas estimates the weather-normalization adjustment for the unbilled revenue each month. The weather-normalization adjustment is evaluated each month and reconciled on an annual basis in the summer to agree with the amount billed to customers.

Rate Regulation

Regulatory agencies establish rates for the storage, transportation, distribution and sale of natural gas. The regulatory agencies also regulate, among other things, the extension and enlargement or abandonment of jurisdictional natural gas facilities. Regulation is intended to permit the recovery, through rates, of the cost of service, including a return on investment. Questar Gas and Questar Pipeline follow SFAS 71, “Accounting for the Effects of Certain Types of Regulation,” that requires the recording of regulatory assets and liabilities by companies subject to cost-based regulation. The FERC, PSCU and PSCW have accepted the recording of regulatory assets and liabilities.

Employee Benefit Plans

The Company has pension and post-retirement-benefit plans covering a majority of its employees. The calculation of the Company’s expense and liability associated with its benefit plans requires the use of a number of assumptions that the Company deems to be critical. Changes in these assumptions can result in different expenses and liabilities and actual experience can differ from these assumptions.

Independent consultants hired by the Company use actuarial models to calculate estimates of pension and post-retirement benefits expense. The models use key factors such as mortality estimations, liability discount rates, long-term rates of return on investments, rates of compensation increases, amortized gain or loss from investments and medical-cost trend rates. Management makes assumptions based on market indicators and advice from consultants. The Company believes that the liability discount rate and the expected long-term rate of return on benefit plan assets are critical assumptions.

The assumed liability discount rate reflects the current rate at which the pension benefit obligations could effectively be settled. Management considers the rates of return on high-quality, fixed income investments and compares those results with a bond-defeasance technique. The Company discounted its future pension liabilities using rates of 6.50% and 6.75% as of December 31, 2005, and 2004, respectively. A 0.25% decrease in the discount rate increased the Company’s 2005 qualified pension annual expense by $1.5 million.

The expected long-term rate of return on benefit plan assets reflects the average rate of earnings expected on funds invested or to be invested to provide for the benefits included in the benefit plan liability. The Company establishes the expected long-term rate of return at the beginning of each fiscal year giving consideration to the benefit plan’s investment mix and the historical and forecasted rates of return on these types of securities. The expected long-term rate of return determined by the Company was 8.25% and 8.50% as of January 1, 2005, and 2004, respectively. Benefit plan expense typically increases as the expected long-term rate of return on plan assets decreases. A 0.25% decrease in the expected long-term rate of return causes a $0.6 million increase in 2005 pension expense.

Recent Accounting Developments

Refer to Note 1 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for a discussion of recent accounting developments.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Questar’s primary market risk exposures arise from commodity price changes for natural gas, oil and NGL, estimation of gas and oil reserves and volatility in interest rates. Energy Trading has long-term contracts for pipeline capacity and is obligated for transportation services with no guarantee that it will be able to recover the full cost of these transportation commitments.

Commodity Price Risk Management

Market Resources bears the risk associated with commodity price changes and uses gas- and oil-price-hedging arrangements in the normal course of business to limit the risk of adverse price movements. However these same arrangements typically limit future gains from favorable price movements. Hedging contracts are used for a significant share of Questar E&P-owned gas and oil production and for a portion of gas- and oil-marketing transactions and for some of Gas Management’s NGL.

Market Resources has established policies and procedures for managing commodity price risks through the use of derivatives. Natural gas- and oil-price hedging supports Market Resources’ rate of return and cash-flow targets and protects earnings from downward movements in commodity prices. The volume of hedged production and the mix of derivative instruments are regularly evaluated and adjusted by management in response to changing market conditions and reviewed periodically by the Finance and Audit Committee of the Company’s Board of Directors. Market Resources may hedge up to 100% of forecast production from proved reserves when prices meet earnings and cash-flow objectives. Market Resources does not enter into derivative arrangements for speculative purposes and does not hedge undeveloped reserves or equity NGL.

Hedges are matched to equity gas and oil production, thus qualifying as cash-flow hedges under the accounting provisions of SFAS 133 as amended and interpreted. Gas hedges are typically structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. Any ineffective portion of hedges is immediately recognized in income. The ineffective portion of hedges was not significant in 2005 and 2004.

As of December 31, 2005, approximately 142.8 Bcf of forecast gas production for 2006, 2007 and 2008 was hedged at an estimated average price of $6.62 per Mcf, net to the well (which reflects assumed adjustments for regional basis, gathering and processing costs and gas quality).

Questar enters into commodity price hedging arrangements with creditworthy counterparties (banks and industry participants) with a variety of credit requirements. Some contracts do not require the Company to post cash collateral, while others allow some amount of credit before requiring deposits of collateral for out-of-the-money hedges. The amount of credit available may vary depending on the credit rating assigned to the Company’s debt securities. A substantial increase in the price of natural gas, oil and/or NGL could result in the requirement to deposit large amounts of collateral with counterparties that could seriously impact the Company’s cash liquidity. Additionally a downgrade in the Company’s credit ratings to sub-investment grade could result in the acceleration of obligations to hedge counterparties. In addition to the counterparty arrangements, Market Resources has a $200 million long-term revolving-credit facility with banks that was not utilized at December 31, 2005.

A summary of Market Resources hedging positions for equity production as of December 31, 2005, is shown below. Prices are net to the well. Currently all hedges are fixed-price swaps with creditworthy counterparties, allowing Market Resources to achieve a known price for a specific volume of production delivered into a regional sales point. The swap price is then reduced by gathering costs and adjusted for product quality to determine the net-to-the-well price.

Market Resources held gas price hedging contracts covering the price exposure for about 184.4 million MMBtu of gas, 2.9 MMbbl of oil and 10.1 MMgal of NGL as of December 31, 2005. A year earlier Market Resources’ hedging contracts covered 135.6 million MMBtu of natural gas, 1.1 MMbbl of oil and 3.8 MMgal of NGL. Market Resources may hedge NGL prices in its processing business.

The following table summarizes changes in the fair value of hedging contracts from December 31, 2004 to December 31, 2005:

A table of the net fair value of hedging contracts as of December 31, 2005, is shown below. About 69% of the fair value of all contracts will settle and be reclassified from other comprehensive income in the next 12 months.

The following table shows sensitivity of the mark-to-market valuation of hedging contracts to changes in the market price.

Credit Risk

Market Resources requests credit support and, in some cases, prepayment from companies with unacceptable credit risks. Market Resources' five largest customers are BP Energy Company, Nevada Power Company, ONEOK Energy Services Company LP, Coral Energy Resources, LP and Sempra Energy Trading Corp. Sales to these companies accounted for 20% of Market Resources revenues before elimination of intercompany transactions in 2005, and their accounts were current at December 31, 2005.

Questar Pipeline requests credit support, such as letters of credit and cash deposits, from those companies that pose unfavorable credit risks. All companies posing such concerns were current on their accounts at December 31, 2005. Questar Pipeline’s largest customers include Questar Gas, PacifiCorp, Colorado Interstate Gas, EOG Resources and Anadarko Petroleum.

Interest Rate Risk

The Company had $983.5 million of fixed-rate long-term debt at December 31, 2005. The fair value of fixed-rate debt is subject to change as interest rates fluctuate. The fair value of Questar's long-term debt amounted to $1.04 billion at December 31, 2005. The Company had $933.5 million of fixed-rate long-term debt at December 31, 2004 with a fair value of $1.03 billion at December 31, 2004. If interest rates declined 10%, fair value would increase to $1.06 billion in 2005 and $1.05 billion in 2004. The fair value calculations do not represent the cost to retire the debt securities.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Financial Statements:

Report of Independent Registered Public Accounting Firm

Consolidated Statements of Income, three years ended December 31, 2005

Consolidated Balance Sheets at December 31, 2005 and 2004

Consolidated Statements of Common Shareholders' Equity, three years ended

December 31, 2005

Consolidated Statements of Cash F